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HomeMy WebLinkAbout2018-09-05 Utilities Advisory Commission Agenda PacketAMERICANS WITH DISABILITY ACT (ADA) Persons with disabilities who require auxiliary aids or services in using City facilities, services or programs or who would like information on the City’s compliance with the Americans with Disabilities Act (ADA) of 1990, may contact (650) 329-2550 (Voice) 24 hours in advance. NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956 I. ROLL CALL II.ORAL COMMUNICATIONS Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable time restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from discussing or acting upon any topic initially presented during oral communication. III.APPROVAL OF THE MINUTES Approval of the Minutes of the Utilities Advisory Commission Meeting held on August 1, 2018 IV.AGENDA REVIEW AND REVISIONS V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS VI.GENERAL MANAGER OF UTILITIES REPORT VII.COMMISSIONER COMMENTS VIII.UNFINISHED BUSINESS - None IX.NEW BUSINESS 1.Discussion of the 2018 Electric Integrated Resource Plan (EIRP) Discussion and Related Documents 2.Staff Recommendation that the Utilities Advisory Commission Recommend Action that Council Accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan, Including Advanced Metering Infrastructure- Based Smart Grid Systems to Serve Electricity, Water, and Natural Gas Utility Customers 3.Discussion of 2019 California Energy Standards and Associated Rooftop Solar Mandate Discussion 4.Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action NEXT SCHEDULED MEETING: October 3, 2018 ADDITIONAL INFORMATION - The materials below are provided for informational purposes, not for action or discussion during UAC Meetings (Govt. Code Section 54954.2(a)(2)). 12-Month Rolling Calendar Public Letter(s) to the UAC UTILITIES ADVISORY COMMISSION WEDNESDAY, SEPTEMBER 5, 2018 – 7:00 P.M. COUNCIL CHAMBERS Palo Alto City Hall – 250 Hamilton Avenue Chairman: Michael Danaher  Vice Chair: Judith Schwartz  Commissioners: Arne Ballantine, Lisa Forssell, A. C. Johnston, Lauren Segal and Terry Trumbull  Council Liaison: Eric Filseth Utilities Advisory Commission Minutes Approved on: Page 1 of 11 UTILITIES ADVISORY COMMISSION MEETING MINUTES OF AUGUST 1, 2018 REGULAR MEETING CALL TO ORDER Chair Danaher called the meeting of the Utilities Advisory Commission (UAC) to order at 7:04 p.m. Present: Chair Danaher, Commissioners Ballantine, Forssell, Johnston, Segal, and Trumbull Absent: Vice Chair Schwartz ORAL COMMUNICATIONS Nicole Sandkulla, Bay Area Water Supply and Conservation Agency (BAWSCA) Chief Executive Officer, advised that the draft Bay-Delta Plan update could seriously reduce water supply during the next drought. BAWSCA's analysis indicates during a drought most water users could be required to reduce their average per person water use to 41 gallons per day and for some persons 25 gallons per day. The severe water reduction could threaten jobs and delay community development. The San Francisco Public Utilities Commission (SFPUC) has proposed and BAWSCA supports a science-based alternative that strikes a reasonable and sustainable balance between water supply reliability and increased salmon population on the Tuolumne River. BAWSCA and water providers in the area have advocated for a voluntary, negotiated settlement to resolve these issues. Governor Brown has expressed support for the approach. Commissioner Trumbull disagreed with Ms. Sandkulla's comments regarding the implications of the Bay- Delta Plan update. APPROVAL OF THE MINUTES Commissioner Trumbull noted that in the minutes of the June 6, 2018 meeting to order the person calling the meeting to order was Vice Chair Ballantine , not Chair Danaher. Commissioner Trumbull moved to approve the minutes from the June 6, 2018 regular meeting as amended. Commissioner Segal seconded the motion. The motion carried 3-0 with Commissioners Ballantine, Segal, and Trumbull voting yes, Chair Danaher and Commissioners Forssell and Johnston abstaining, and Vice Chair Schwartz absent. AGENDA REVIEW AND REVISIONS None REPORTS FROM COMMISSIONER MEETINGS/EVENTS None UTILITIES GENERAL MANAGER REPORT Ed Shikada, Utilities General Manager, delivered the General Manager’s Report. DRAFT Utilities Advisory Commission Minutes Approved on: Page 2 of 11 Carr Wildfire Impacts on Hydroelectric Resources - Staff have been working closely with the Northern California Power Agency (NCPA) to monitor impacts of the Carr Fire on hydroelectric resources in the area around Redding. Hydroelectric resource deliveries from the Western Area Power Administration and Bureau of Reclamation projects were interrupted for several days until crews were able to access the facilities and restore power deliveries to about 40% of what would be expected without the fire. They will continue restoration efforts to return to full electric delivery capability. It does not appear that the California Independent System Operator (CAISO) is suffering operational issues as a result, but we will monitor and respond to any requests from CAISO for an energy conservation Flex Alert. Wildfire Mitigation Plan - Utilities has a consent item on the August 20 City Council agenda which will satisfy a new state law regarding wildfire preparedness for electric utilities. The law mandates that a utility's governing body adopt wildfire mitigation plans after determining that an area within its jurisdiction, if any, is at “significant risk of catastrophic wildfire” resulting from electric lines or equipment. The staff report requests that Council designate the Foothills area as potentially high risk for wildfires, and accept mitigation measures already contemplated by staff. To be clear, there is no new or enhanced risk. We present this purely administrative item only to comply with the law. Fiber to the Node RFP - The City received six responses to the Fiber to the Node RFP and we are now entering phase two of the evaluation by inviting the top 5-ranked proposers for demonstrations during the week of August 13. If one or two members of the UAC are interested in participating on the evaluation panel and are able to attend all five 90 minute interviews, please contact Dave Yuan. SunShares 2018 Solar Group-Buy Program - For the fourth year in a row, the City is participating in Bay Area SunShares, a solar and zero-emissions vehicle group-buy program administered by the Building Council for Climate Change, BC3. Beginning today, August 1, Bay Area residents can take advantage of discounts on rooftop solar and zero-emission vehicles from vetted contractors. The program runs for a limited time only through November 15. Visit www.cityofpaloalto.org/sunshares for details and join us for a free workshop on September 29. Utilities Awarded Two Climate Protection Grants from the Bay Area Air Quality Management District (BAAQMD). Utilities was awarded two grants from the Bay Area Air Quality Management District, which will enable the City to offer a refrigerator recycling program and conduct a pilot study on gas furnace replacements in multi-family buildings. Each program is designed to help the City save energy and reduce greenhouse gas emissions. We will provide more details upon official launch of the programs. Draft Bay Area Plan – The draft Bay Area Plan is tentatively scheduled for City Council discussion on August 20. COMMISSIONER COMMENTS Chair Danaher announced Commissioners are invited to attend presentations from the five proposers for the Fiber to the Node project. However, Commissioners must attend all or none of the presentations in accordance with instructions from the City Attorney's Office. The presentations are scheduled for the morning of August 13, the afternoon of August 14, and the morning of August 15. UNFINISHED BUSINESS None NEW BUSINESS ITEM 1: ACTION: Staff Request for Direction and Feedback on Utility Rules and Regulations Requiring Pad- Mounted Equipment in All Underground Electric Construction, Including Green Acres. Chair Danaher advised that the City began undergrounding power lines about 45 years ago. Currently, approximately 25% of power lines in the City has been undergrounded. Staff is starting to replace Utilities Advisory Commission Minutes Approved on: Page 3 of 11 transformers in chronological order of installation. In the early years of undergrounding power lines, neighborhoods paid 25% of the installation cost. The pace for undergrounding power lines is one neighborhood every 3-5 years because of the high cost of projects. He invited the public to opine as to whether their neighborhoods would agree to share in the cost of undergrounding. Ed Shikada, Utilities General Manager, acknowledged the anxiety caused by the topic of undergrounding power lines. Staff's proposal is based on the City of Palo Alto Utilities' (CPAU) commitment to deliver safe, reliable, and cost-effective utility services. Staff does not wish to proceed over the objections of the community. Nina Bell believed the 4-foot aboveground transformer would be a desecration. The Comprehensive Plan states that the City will strive to preserve and complement neighborhood character when installing streets or public-space improvements. She wanted to review and understand financial information before deciding to share in the installation costs. Jeff Hoel noted the City Council approved placing transformers aboveground in 1996. He inquired regarding staff's plans to re-use the existing conduit and the expected lifetimes of conduit installed in 1973 and in 2018. If replacing the infrastructure requires digging, then the project should include installation of conduit for fiber. Implementing Supervisory Control and Data Acquisition (SCADA) for transformers could be interesting. Alice Sklar remarked that aging utility facilities are in danger of breaking down, causing damage, injuring citizens, and interrupting service. She preferred utilities be located entirely underground. Green Acres residents have discussed and researched the issues. The Green Acres Improvement Association Board wants to review the evidence supporting assertions that fully underground utilities are dangerous to residents or the community. She would be willing to share the costs of installation if the financial information can convince her that the amount is $3,600. Eugene Lee expressed concerns about the effects of electromagnetic fields (EMF) generated by transformers on human health. The proposed plan shows a transformer located within 20 feet of a bedroom in his home. Jenning Chee felt the proposed plan would modify his home without his agreement. There was no compelling reason for the proposed action. The City should have budgeted for maintenance when it originally undergrounded the equipment. Garbo Lee indicated a transformer would be placed less than 20 feet from her bedroom if the project is approved. The current location of utilities should be maintained. In March, she received notice of Staff's proposal only a few days before the UAC meeting. She would not agree to share the cost of installation as property owners paid for the original installation. Yu Fang wanted all facilities placed underground. The City required his home remodel to maintain the character of the neighborhood, and CPAU should be subject to the same requirement. Technology should be available so that all facilities can be placed underground. Residents received notice of the matter only a few days before the hearing. CPAU staff promised pad-mounted transformers would not be forced upon residents. Lin Lui requested staff provide their data, research, and analysis to residents. She expressed concerns about the safety of aboveground transformers. She would not consider paying for installation until residents' questions are answered. Stuart Kreitman wished to obtain staff's information and verify it for accuracy. Residents do not understand the technical aspects and safety of pad-mounted transformers. The Special Facilities fee does not appear to apply to transformers or shared infrastructure. Utilities Advisory Commission Minutes Approved on: Page 4 of 11 Frankie Farhat advised that any change to the current situation would have a negative impact on the neighborhood. She suggested the upgrades be implemented in other neighborhoods before Green Acres. CPAU should underground all facilities in Green Acres or delay the project until residents could review staff's data. Michael Maurier commented that the proposal was poorly presented to residents. Residents are overwhelmingly opposed to pad-mounted transformers because they have not received requested information. He understood the general trend in Palo Alto was to underground all components. Staff has not offered a rationale for not placing all components underground. The proposal is contrary to the Comprehensive Plan policy to preserve the neighborhood character. He suggested facilities in Green Acres not be replaced until there is a problem, until the City can pay for it, or until residents can find a way to pay for it. Residents have not seen any justification for the stated amounts. Debbie Tasso [phonetic] concurred with Mr. Maurier's comments. Underground utilities have not caused any health problems and have provided excellent and reliable service. She could not find any data regarding the safety of pad-mounted transformers. The safest location of transformers is underground. She may be willing to pay for installation after reviewing a cost analysis. Debra Lloyd, Acting Assistant Director of Utilities Engineering, reported the undergrounding program began in 1965. Underground utilities have been installed in 43 districts. Work on Underground Districts 46 and 47 is underway. Staff coordinates projects to underground electric, fiber, cable, and telephone systems with AT&T and Comcast projects. Property owners pay the costs for connecting to underground utilities and may share the costs for undergrounding the system. In response to Commissioner Forssell's request for the cost to property owners, Lloyd indicated the cost to property owners in District 47 is $3,000-$5,000 for service connection alone. District 47 property owners did not share in the cost for undergrounding the system. Property owners share in the cost for undergrounding the system when undergrounding is deemed a public benefit rather than a local benefit. Lloyd continued by stating residents of Green Acres petitioned the City to underground utilities in 1972 and paid $300 for a service connection and $310.25, 25% of the total cost, for undergrounding the system. The original equipment is still in use in Green Acres. Based on the total number of primary electric distribution lines, 62% have been undergrounded, the majority of which is located in commercial areas. Approximately 2,500 residences are located in districts where overhead service has been converted to underground. All new housing developments are constructed with underground facilities. Approximately 14,000 residences remain to be undergrounded. In reply to Commissioner Johnston's query regarding the use of pad-mounted or underground transformers in new developments, Lloyd related that transformers are pad-mounted. In commercial areas, transformers are placed underground when space is not available for pad-mounted transformers. In answer to Commissioner Ballantine's question regarding installation of a concrete vault for underground facilities in commercial areas, Gregory McKernan, Senior Engineer, explained that transformers are pad- mounted with conductors located in underground vaults. Commissioner Ballantine understood a large concrete vault is placed underground to house the transformer and other equipment. Dean Batchelor, Chief Operating Officer, clarified that large transformers are pad-mounted in commercial areas such as Stanford Research Park because ground space is available for the transformer. In Downtown where ground space is not available, transformers are placed in large concrete vaults under the street. Commissioner Ballantine suggested concrete vaults in 2018 are much larger than those installed in the 1970s to address safety concerns. Batchelor reported vaults can measure from 4 feet by 6 feet up to 10 feet by 13 feet. Utilities Advisory Commission Minutes Approved on: Page 5 of 11 Lloyd continued with her presentation, indicating the expected lifespan of the 1970s equipment is 35-40 years for the cable and 15 years for the transformers. Staff begins planning replacement projects before system failures occur. Commissioner Ballantine suggested staff provide the average lifespan of an underground transformer compared to the average lifespan of a pad-mounted or pole-mounted transformer. He was fairly certain transformer lifespan and failure was proportional to the load it bears. The increasing use of electric vehicles (EV) adds to the load on transformers. Consequently, the current statistics for transformer lifetime may change in the very near future. Lloyd added that the load on transformers located in Green Acres likely contributed to their long life. The probability of failure increases each year a system remains in service beyond the expected lifespan. Engineering experience suggests multiple outages will occur when system failure begins. Commissioner Ballantine recalled that the average lifespan for a pole-mounted transformer is 50 years and for an underground transformer is 15 years. If those numbers are correct, the transformers in Green Acres have lasted because the load on them has been less than they are capable of handling. Pole- mounted transformers in the same circumstances could last even longer. Perhaps the transformers' lifespans have been extended because the size of the transformers was larger than required or the locations have not been flooded. That type of data would be useful. Lloyd reported staff shared a table comparing underground, pad-mounted, and pole-mounted transformers at the community. Lloyd further advised that replacement projects begin in 1995. The replacement project for Districts 6 and 7 converted underground transformers to pad-mounted transformers. In response to Commissioner Johnston's inquiry about the number of underground districts that have been rebuilt, Lloyd stated two residential districts, Districts 6 and 7, and at least a dozen commercial districts have been rebuilt. District 6 is geographically close to District 15. Transformers were converted to pad-mounted in rebuild projects except in commercial districts where space was not available. In reply to Commissioner Forssell's question regarding the date of rebuilding the system in District 6, Lloyd answered 2003 or 2001. The number of pad-mounted transformers installed in District 6 should be similar to the number proposed for Green Acres. Technology has not changed significantly since 2003 to require a different configuration. Lloyd continued with information about rebuild projects. Staff has identified 13 districts for rebuild because the equipment's expected lifespan will expire by 2024. Many of the 1,700 properties located in the 13 districts are residential. Approximately 270 transformers in the 13 districts will be replaced. The Capital Improvement Program (CIP) contains rebuild projects for seven districts, which will affect approximately 860 properties and approximately 120 subsurface transformers. Currently, projects are in design for Districts 15, 16, 20, 23, and 30, which will involve 785 properties and approximately 100 subsurface transformers. McKernan reported in designing projects for underground districts, staff considers employee safety, the reliability of the system, the purchase and maintenance of equipment, the capacity and flexibility of the system, and industry standard. In answer to Commissioner Forssell's query regarding the locations of pad-mounted transformers, McKernan explained that staff can locate a pad-mounted transformer within 50-100 feet of the existing subsurface vault depending on the load on the transformer. Staff has some flexibility to relocate transformers shown in the plans for Green Acres. Because existing vaults are located beneath sidewalks in Green Acres, the pad- mounted transformers would not be placed over the vaults. Commissioner Ballantine noted the Occupational Safety and Health Association (OSHA) has issued clearance requirements for electrical equipment. Existing vaults may not comply with OSHA requirements. Utilities Advisory Commission Minutes Approved on: Page 6 of 11 McKernan continued, reporting that water and heat cause metals to corrode, which increases maintenance costs for subsurface vaults. Water and debris must be removed and disposed of prior to staff repairing equipment in subsurface vaults. In reply to Councilmember Filseth's question regarding placing pumps in underground vaults, McKernan indicated CPAU does not place pumps in subsurface vaults. Ed Shikada, Utilities General Manager, added that portable pumps are used to evacuate water. In response to Commissioner Forssell's inquiry regarding damage to electrical equipment from submersion in water and oil, McKernan clarified that water and oil corrodes the tank on the transformer. Transformers located in Green Acres have required repairs. Commissioner Ballantine remarked that water breaching the transformer tank will cause the transformer to fail and a significant power outage. That would be a significant safety hazard for people working on it. In reply to Chair Danaher's question regarding waterproof vaults, McKernan explained that a waterproof vault would not have vents that allow air circulation. The buildup of heat would cause failure. McKernan presented pad-mount design options that include placement and screening of the transformer. In answer to Chair Danaher's query, McKernan advised that staff will find locations for transformers such that the transformers are screened and less noticeable. McKernan reported additional design options are to separate the equipment into different locations to increase safety and to utilize larger transformers to minimize outages. In response to Commissioner Johnston's question regarding the black squares on the map provided by Shikada, McKernan explained that the squares represent underground boxes that connect service to residences and carry conductors to the transformer. The top of the box will be flush with the street to provide access. Lloyd added that the map is not Green Acres. In reply to Commissioner Forssell's question regarding the symbol representing pad-mounted transformers, McKernan answered the box with the triangle inside it. In answer to Commissioner Segal's question regarding the size of the pad-mounted transformers in Green Acres, McKernan indicated some transformers proposed for Green Acres have dual functions and, consequently, are approximately 15 inches wider than the transformers installed in District 6. If smaller transformers are used in Green Acres, then an additional piece of equipment will be installed. In reply to Commissioner Ballantine's query regarding the configuration inside the transformer, McKernan advised that transformers have a primary and a secondary winding. Commissioner Ballantine had seen a winding in a hexagon pattern, which cost more but was half the size of a traditional transformer. Lloyd continued with the presentation, advising that staff had not considered placement, size, and screening of transformers in the preliminary design. McKernan added that staff considered future load when recommending the size of transformers. Lloyd reported maintaining all underground structures in Green Acres would require a policy change. Issues for consideration are paying for the more costly rebuild project, whether through cost-sharing with property owners or implementing a Special Facilities fee; the size and duration of outages; and the impacts to staff in planning and implementing projects. McKernan advised that underground transformers cost approximately $345,000 more than pad-mounted and will require a second vault to separate the transformer from cables. The number of transformers would be the same for underground and pad-mounted installations. With some pad-mounted transformers, switches can be eliminated, which means lower maintenance and operation costs. The primary difference in cost is the second vault. Utilities Advisory Commission Minutes Approved on: Page 7 of 11 In response to Chair Danaher's inquiry regarding the source of cost estimates, McKernan indicated equipment costs are based on quotes from manufacturers. The cost estimate to install a vault is approximately $25,000. In answer to Commissioner Forssell's query regarding safety concerns with a potential subsurface design, McKernan indicated staff would design a subsurface project that was safe for employees; however, subsurface transformers will always be hazardous in a catastrophic event. PG&E and Southern California Edison transformers have exploded while undergoing repairs. Batchelor added that a PG&E incident involved a fatality and related an incident that occurred in San Francisco. Commissioner Ballantine remarked that water in an underground vault increases the probability of a transformer explosion. Data regarding the effectiveness of EMF shielding could be useful. Placing transformers in the safest possible location is important. Chair Danaher recalled the Green Acres residents' requests for data regarding costs, safety, and alternative sizes. Shikada reported staff searched for published reports and statistics regarding safety but was unable to locate any. Commissioner Ballantine remarked that discovering a solid solution is less of a solution is frustrating. Everyone is concerned about the safety, aesthetics, and the value of their homes, but safety is probably the primary concern. He probably would not pay for an underground transformer near his house because of worries that the transformer would fail or explode. More and more people rely on consistent power for their health and safety. Perhaps the size of aboveground transformers can be reduced. There are federal standards for EMF strength from transformers. The EMF from a shielded transformer is probably quite a bit lower than a field from most devices commonly found in homes. Contemplation of casualties from transformer failures and explosions is sobering. Staff is attempting to figure out how to provide electricity to homes in the safest possible manner. Commissioner Johnston was persuaded that pad-mounted transformers are logical, but more work with the community is needed for design alternatives. Pad-mounted transformers are common, and after a while people do not notice them. Answering the community's questions could facilitate future rebuild projects. If CPAU offers fully undergrounded rebuilds as an option, asking residents to pay for the additional cost is reasonable. Commissioner Forssell continued to struggle with the size of pad-mounted transformers. Accurate sizes are needed for proposed and alternative transformers. Shikada clarified that the transformers shown on Donald Drive, which are 34 inches tall by 44 inches wide by 33 inches deep, are smaller than the proposed Green Acre transformers, which are 38 inches tall by 48 inches wide by 39 inches deep. Because of the perspective, Ms. Bell's photographs give the impression that the boxes are larger than they are. Commissioner Forssell noted that the 1996 City Council did not expect to rebuild the underground districts. Therefore, the City Council likely did not consider the current situation in its decision. She inquired regarding the mechanism by which the City has the right to place equipment on residents' property and any limits to that right. McKernan explained that the City owns the real property beneath a right-of-way. Through an easement, a property owner grants the City access to real property to place equipment on the property. In the rebuild project, equipment would be placed in the public right-of-way, not on private property. Shikada clarified that 5-feet on the home side of a sidewalk is owned by the City, and that's where the equipment would be placed. Commissioner Segal was disappointed that much of the factual information presented during the meeting was not disclosed during the community meeting. Shikada reported residents were not interested in discussing minimizing the size of transformers at the community meeting. The conversations pertained mainly to options that did not involve aboveground cabinets. Commissioner Segal expressed interest in options and sizes for pad-mounted transformers. Hopefully, aesthetics can be accommodated without compromising safety. Utilities Advisory Commission Minutes Approved on: Page 8 of 11 Commissioner Trumbull hoped staff would work with the residents to address residents' concerns. Chair Danaher commented that residents would likely share in the cost of installing transformers underground if cost and aesthetics are the only considerations and if they have a long-term payment plan. Because safety is the key criteria, transformers should be pad-mounted with consideration of size, placement, screening, and decoration of transformers. If residents raise similar concerns in future rebuild projects, then the issue may need to return to the Council. Shikada advised that staff will continue searching for information to share with the UAC and community and will work with residents regarding options for location, size, and aesthetics. Chair Danaher requested staff research the safety, aesthetics, and health concerns of pad-mounted transformers. Councilmember Filseth reported he has a better understanding of the situation after hearing public comments and Commissioner questions. The chances of a catastrophic event were remote; however, a casualty would be terrible. No matter the amount of data available for review, the decision will be qualitative. ACTION: No action ITEM 2. DISCUSSION: Discussion of Natural Gas Capital Improvement Plan. Ed Shikada, Utilities General Manager, reported the item is informational for the UAC because the Finance Committee requested the report as a follow-up to its discussion of the City budget. Given the late hour it was staff’s preference to postpone this item. Chair Danaher agreed to postpone the item. ACTION: No action ITEM 3. DISCUSSION: Discussion of Recycled Water Distribution System Business Plan. Karla Dailey, Senior Resource Planner, reported the Regional Water Quality Control Plant (RWQCP) produces more recycled water than is used. Recycled water is high-quality, drought-proof, locally controlled, and non- potable. The Phase 3 expansion was originally proposed in the 1992 Recycled Water Master Plan. In September 2015, the City Council certified an Environmental Impact Report (EIR) for Phase 3 and stated staff should not present any proposal to build Phase 3 without exploring a broad range of alternatives uses for recycled water. Phase 3 will not be possible without an advanced water purification system to reduce the salinity of recycled water. The Northwest County Recycled Water Strategic Plan includes the Phase 3 pipeline, which includes 30% pre-design, a business plan, and funding ; the feasibility of indirect potable water reuse; assessment of direct potable water reuse; and a regional overview of potential recycled water demands. In the Northwest County Recycled Water Strategic Plan, potable water supply resource planning refers to the Water Integrated Resources Plan; the plan will be updated once staff has a better picture of recycled water alternatives. The study of the Mountain View recycled water distribution expansion and Sunnyvale tie-in has been completed but not the actual tie-in. The RWQCP provides most of the recycled water supply to Mountain View; however, recycled water is also supplied to the golf course, Greer Park, and some other City facilities. The route of the Phase 3 pipeline has been adjusted since the original 1992 plan to meet customer demands and to supply the Baylands Athletic Center. In reply to Commissioner Trumbull's query regarding Stanford University's use of recycled water, Dailey advised that Stanford University is not an enthusiastic supporter of recycled water use. Because of Stanford University's concerns around use of recycled water in Stanford Research Park, CPAU commissioned the EIR and agreed to reduce the salinity of recycled water. Utilities Advisory Commission Minutes Approved on: Page 9 of 11 Dailey continued, stating the Phase 3 plans show a connection to the Phase 2 transmission main, 10 miles of transmission and distribution pipelines, two pump stations, and 200 customer connections. Demand for recycled water is approximately 1,000 acre feet per year, which is approximately 10% of Palo Alto's potable water demand. The estimated cost of Phase 3 is around $3,000 per acre foot. The construction cost estimate is $36.8 million with a total capital cost estimated at $45 million. One benefit of the Phase 3 project is system reliability enhancement, which is the concept that every water customer benefits from the use of recycled water whether or not a customer has access to or uses recycled water. Potential sources of funding for the project are the State Revolving Funds and state and federal grants. The use of recycled water is consistent with the City's sustainability goals. The project will provide benefits by reducing the demand for potable water, reserving potable water for appropriate uses, enhancing landscaping for recreation and aesthetics, allowing the City to retain local control, and alleviating pressure on the Tuolumne River. Currently, CPAU does not charge a rate for recycled water because recycled water is used by City facilities only. With the pipeline expansion to Stanford Research Park adding 200 customers, recycled water would be treated as a utility with a rate schedule. Staff has not conducted a cost-of-service study but will do so. Typically, California recycled water rates are 60-90% of potable water rates. Because of the cemetery located at the terminus of the Phase 3 pipeline, staff will investigate a reduced project that does not extend to the cemetery. Staff attempted to quantify a rate of reliability enhancement under various funding scenarios. With no external funding for the project, the reliability rate is in the range of $150-$200 per acre foot. With all external funding for the project, the rate is approximately $50 per acre foot. The most likely reliability rate in 2030 would be approximately $100 per acre foot. In response to Commissioner Forssell's request for the definition of reliability rate, Dailey indicated the reliability rate is the amount of money that potable water users pay towards the recycled water pipeline project. Conceptually, the reliability of potable water increases with a reduction in pressure on imported water supplies. Chair Danaher clarified that the use of recycled water increases the supply of potable water. Dailey restated the concept as use of recycled water decreases the demand for potable water. In answer to Commissioner Ballantine's query about the effect of decreasing demand on rates, Jonathan Abendschein, Assistant Director of Resource Management, advised that decreased demand can result in increased rates in the short term. Over the long term and with efficiency, ratepayer bills tend to decrease. A future task for staff is to determine the impact on potable water rates. The amount that potable water rates would increase is the reliability rate. Carrie Del Boccio, Woodward and Curran, added that revenues lost from declining sales of potable water would be shown initially as a loss but would eventually be included in rates for potable water. Councilmember Filseth suggested the concept is paradoxical as the primary use of recycled water is landscape irrigation. During a drought, irrigation of landscape should be the first reduction. Abendschein commented that some irrigation of landscape, such as playing fields and trees, was a community concern during the recent drought. The use of recycled water could protect those assets in a future drought. In reply to Commissioner Ballantine's query regarding the cost of raising the quality of recycled water to potable water, Dailey reported staff continues to assess alternatives for water reuse and cannot make a recommendation for the Phase 3 project without the assessments. In response to Commissioner Forssell's question regarding the possibility of increased usage or decreased conservation due to lower rates or the perception of recycled water as "guilt-free," Dailey did not know whether the availability of recycled water would affect usage or conservation. Commissioner Forssell assumed commercial facilities would have little incentive to conserve recycled water in a drought because there was no storage facility for recycled water. In answer to Commissioner Ballantine's query regarding regulations for use of evaporative chillers in drought conditions, Del Boccio advised that industrial cooling towers and other facilities use more water if the salinity of the water is higher than potable water. Dailey advised that there were no restrictions on the use of Utilities Advisory Commission Minutes Approved on: Page 10 of 11 evaporative chillers in the last drought. Commissioner Ballantine suggested a commercial customer could purchase recycled water at a lower cost, reduce the salinity onsite, and utilize the chiller as much as necessary in a drought. In reply to Chair Danaher's question regarding alternative uses of project funding that would conserve water, Dailey indicated the Recycled Water Strategic Plan will identify the best alternatives for water reuse, and alternatives will be incorporated into the Water Integrated Resources Plan. Regardless of the amount of conservation, staff is interested in reducing dependence on imported water supplies. Additional restrictions on water the RWQCP discharges into the Bay are an incentive for staff to identify a beneficial use of the water. Abendschein added that the Recycled Water Strategic Plan will determine the most cost-effective method to use recycled water. Water supply planning looks at conservation and other ways to save water. In answer to Commissioner Segal's inquiry regarding a less direct pipeline route possibly connecting to more customers, Dailey explained that staff planned the route to serve as many customers as possible. Del Boccio remarked that the goal has been to optimize the number of customers with the shortest route while addressing the most challenging crossings within Palo Alto. Dailey continued the presentation with potential mitigation strategies. Staff has not conducted a full cost-of- service study. Perhaps CPAU could increase the recycled water rate to more than 60% of potable water rate. In addition, staff is looking for alternative uses of the project facilities. Next steps are to evaluate a project that does not extend to the cemetery; In reply to Commissioner Johnston's query regarding a price for recycled water without the 60% cap, Dailey indicated staff's assessment would include that. Dailey further reported that the evaluation would identify opportunities to expand distribution beyond the current terminus of the pipeline. Next steps are to prepare a full cost-of-service study; refine projections for revenue and costs versus benefits; evaluate additional uses that could utilize recycled water; evaluate incorporation of facilities into a future direct potable reuse project; complete the Northwest County Recycled Water Strategic Plan to determine how the project compares to alternatives for use of recycled water. In answer to Commissioner Segal's question regarding minimizing the risk of a stranded asset, Dailey advised that minimizing risk plays into use of the pipeline in a future indirect potable water reuse project Commissioner Johnston believed the primary question is the amount of the reliability enhancement fee charged to all potable water users. A 3-4% increase of existing rates would be acceptable; however, ratepayers could take issue with a higher rate. Commissioner Ballantine commented that a solar-powered upgrading station for recycled water could provide a benefit for local solar. In response to Commissioner Forssell's inquiry about a net present value calculation, Del Boccio referred her to Tables 3.1 and 3.2 in the Business Plan. Chair Danaher recommended staff provide the percentage of water saved over total use in normal and drought conditions in future reports. Dailey hoped to present an item to the UAC in October for broader alternatives. In reply Commissioner Forssell's questions around potential rates per acre foot and a positive net present value, Dailey stated all rates will need to be based on cost of service. The common practice is to include some costs for recycled water borne by potable water ratepayers within the service territory. Abendschein clarified that the range for the reliability rate is $0-$700 per acre foot. The rate that would likely achieve a zero or slightly positive net present value is $150 per acre foot, which is equivalent to an increase of 3-4%. Utilities Advisory Commission Minutes Approved on: Page 11 of 11 Chair Danaher remarked that in a drought with a 40% reduction, the marginal value of having an extra 10% of water is high. The value depends on scarcity. Councilmember Filseth felt users rather than ratepayers should pay for recycled water If most of the recycled water is used to irrigate landscape in a drought. The 60% cap on the recycled water rate seems artificial. Dailey clarified that a recycled water rate above 60% of potable water rates would adversely impact the cemetery. Del Boccio noted use of recycled water for Irrigation outweighs industrial uses of recycled water. Councilmember Filseth added that turning recycled water into potable water has a high value. Given that the uses of recycled water are limited, staff has to look at the appropriateness of charging all ratepayers for recycled water. Commissioner Ballantine suggested the City could require the use of recycled water in swimming pools, but it would change the economics of the project. Dailey advised that the use of recycled water in swimming pools is against the law. Abendschein added that staff had not considered the use of recycled water for swimming pools, which is an onsite direct potable reuse. Staff could explore whether it plays into the Recycled Water Strategic Plan. First, staff needs to complete the Recycled Water Strategic Plan to identify the most cost-effective use of recycled water. Second, staff may be able to find other funding sources. ACTION: No action ITEM 4. ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting. Commissioner Trumbull confirmed that the resiliency workshop is scheduled for August 28. Commissioners requested agenda items for the new California law about solar for new homes and BAWSCA's comments regarding the Bay-Delta Plan update. NEXT SCHEDULED MEETING: September 5, 2018 Meeting adjourned at 10:23 p.m. Respectfully Submitted Rachel Chiu City of Palo Alto Utilities Page 1 of 7 1 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: September 5, 2018 SUBJECT: Discussion of the 2018 Electric Integrated Resource Plan (EIRP) and Related Documents ______________________________________________________________________________ REQUEST This is an informational report for review and discussion by the Utility Advisory Commission (UAC) of the following documents related to the Electric Integrated Resource Plan (EIRP): 1. The Executive Summary of the 2018 EIRP (Attachment A); 2. The EIRP Objective and Strategies to guide future analysis and decisions (Attachment B); and 3. The EIRP Work Plan outlining planned staff initiatives to implement the EIRP (Attachment C). Upon UAC review and input, staff expects to return in October to the UAC for approval of complete and updated set of the three documents. Under the state’s SB350 regulations, the EIRP must be approved by Council by January 1, 2019. EXECUTIVE SUMMARY Palo Alto regularly engages in long-term planning to optimally meet the community’s electrical loads with electric supplies. This planning was previously conducted under the framework of the Long-term Electric Acquisition Plan (LEAP) and in the future will be conducted under the EIRP framework1, which the City is required to complete every five years under state law (SB 350). The current EIRP, which must be approved by Council by January 1, 2019 in order to satisfy the City’s SB 350 regulatory requirements, has a planning period of 2018 through 2030. The City of Palo Alto Utilities (CPAU) currently has sufficient supply resources to meet projected loads through 2030, with approximately 45% of its resources from hydro supplies and the remaining 55% from renewable contracts.2 The City’s 20-year contract with the Western Area Power 1 Staff will hereafter discontinue using the term LEAP and in the future use the term EIRP when seeking long-term electric portfolio plan approvals from the Council. 2 The City’s first long-term renewable contract—for wind power—expires at the end of 2021 and the other wind contract and all five landfill-gas-to energy contracts expire in the late 2020’s or early 2030’s, while the solar contracts all extend beyond 2040. Page 2 of 7 Administration (WAPA) for hydroelectric resources, which supplies nearly 40% of the City’s energy needs in a normal hydro year, expires at the end of 2024. A primary focus of the EIRP is the question of whether to renew the contract with WAPA for an additional 30-year term (and if so, at what participation level) and/or seek other renewable supplies to meet City loads. Along with the Executive Summary section of the City’s final 2018 EIRP 3, this report includes: (1) the proposed EIRP Objective and Strategies to guide future analysis and decisions, which was previously shared with the UAC in June 2018, and (2) a set of new initiatives, and timelines for their completion, that staff recommends undertaking in order to prepare the City’s electric supply portfolio for the upcoming shifts in the electric utility industry—including additional analysis focused on the 2025 Western contract decision and portfolio rebalancing initiatives. Upon UAC review and input, staff will return to the UAC in October with an updated and complete set of these EIRP-related documents for final review and recommendation for Council approval. BACKGROUND The last time the City completed an integrated resource plan (IRP) was in 2012, when the City’s updated Long-term Electric Acquisition Plan (LEAP) was approved by Council on April 16, 2012 (Staff Report 2710, Resolution 9241). A few years later, in 2015, Senate Bill 350 (SB 350) was signed into law, and it includes a requirement that publicly-owned utilities (POUs) serving loads greater than 700,000 megawatt-hours per year, such as Palo Alto, develop and adopt an IRP and submit it to the California Energy Commission (CEC) by January 2019 and every five years thereafter.4 The current EIRP planning period is from 2018 through 2030. As noted in the EIRP report Executive Summary (Attachment A), through 2028 the City has sufficient resources to meet its forecasted electric loads, with renewable power contracts supplying over 50% of its needs and the remainder coming from hydroelectric resources. The City’s contract for the Western hydroelectric resource expires at the end of 2024, but is available to be renewed under similar contractual terms for an additional 30-year period. A major consideration for the EIRP—and the subject of a significant amount of the efforts outlined in the work plan (Attachment C)—is whether to renew the contract with Western (and if so, at what participation level) and/or seek other carbon neutral power supplies.5 Staff presented a preliminary analysis of the City’s long- term electric supply portfolio and a variety of potential new resource options (including the 3 The full EIRP report, along with its required attachments, will be presented to the UAC for approval in October. 4 The Clean Energy and Pollution Reduction Act of 2015 also raised the state’s renewable portfolio standard (RPS) to 50% by 2030 and required a doubling of energy efficiency savings by 2030. The primary objective of the IRP requirement in SB 350 is to ensure that the state’s large POUs are on track to reduce their greenhouse gas emissions, helping the state meet its overall target of reducing GHG emissions to 40% below 1990 levels by 2030. 5 Based on the current milestone schedule presented by the Western Area Power Administration (WAPA) related to the post-2024 contract extension process, staff’s understanding is that the City must execute the new contract, accepting the updated project allocation, by April 2020. However, according to WAPA there will be a “one-time contract reduction/termination provision” available to customers who execute the new contract in July 2024. https://www.wapa.gov/regions/SN/PowerMarketing/Documents/2025/2025-milestone-schedule.pdf Page 3 of 7 2025 Western contract), along with draft EIRP Objectives and Guidelines for UAC discussion and input in June 2018 (Attachment D). As part of the 2012 LEAP update, the City Council approved a set of electric portfolio decision- making Objectives and Strategies. At the outset of the current EIRP development process, staff developed an updated Objective and Strategies (Attachment B). The current version, which aligns with the Utilities 2018 Strategic Plan, is very similar to the ones adopted in 2012, with the new Objective and Strategies placing greater emphasis on managing uncertainty related to resource availability and costs, regulatory uncertainty, and the increased penetration of DERs. Beginning in June 2017, staff has presented ten different reports to the UAC and Council (including the present one) directly or indirectly related to the development of Palo Alto’s 2018 IRP. These presentations and reports are summarized in Table 1 below. Table 1: Public Process Summary for Development of the 2018 EIRP Forum Date Topic Link UAC 6/7/2017 Overview of CPAU’s EIRP Development Process Report UAC 8/2/2017 Discussion of DER Plan Development Report UAC 8/2/2017 Discussion of California Wholesale Energy Market and Electric Portfolio Cost Drivers Report UAC 9/6/2017 Discussion of Hydroelectric Resources and Carbon Neutral Portfolio Alternatives Report UAC 11/1/2017 Discussion of Proposed DER Plan Report UAC 12/6/2017 Discussion of Renewable and Carbon Neutral Portfolio Strategy Report UAC 4/12/2018 Assessment of CPAU’s Distribution System to Integrate DERs Report UAC & Council 5/2/18 & 5/21/2018 CPAU Demand Side Management Annual Report – FY 17 UAC, Council UAC 6/6/2018 Long-term Electric Portfolio Analysis Results and Options for Rebalancing Portfolio in the Next Five to Ten Years Report UAC 9/5/2018 2018 EIRP Executive Summary, Objective & Strategies, Work Plan N/A Through these presentations and discussions, staff has laid out the motivations and context for the EIRP, and described the resources currently in the City’s supply portfolio as well as the upcoming planning decisions and uncertainties facing the City. Staff felt that this level of public discussion was important given that: (1) the City must make some important planning decisions in the next several years and (2) the electric utility industry has undergone dramatic changes since Palo Alto prepared its last LEAP update in 2012, with a major shift underway towards greater levels of variable, distributed, low-emissions generation, along with an expanding suite of regulatory mandates that the City must satisfy. CEC IRP Guidelines & Required Elements The schedule and structure of the EIRP process has been dictated in large part by regulatory requirements imposed by SB 350,6 which states that Palo Alto’s IRP must be adopted by Council 6 SB 350 also requires the doubling of energy efficiency savings targets by 2030 and establishes a new Renewable Page 4 of 7 by January 1, 2019, submitted to the CEC by April 30, 2019, and updated at least every five years thereafter. At a minimum, Sections 9621 and 454.52 of the State Public Utilities Code require that the City’s IRP shall: • Ensure procurement of at least 50 percent renewable resources by 2030; • Meet Palo Alto’s share of the greenhouse gas emission reduction targets established by the California Air Resources Board (CARB) for the electricity sector, to enable California to achieve the economy wide greenhouse gas emissions reductions of 40 percent from 1990 levels by 2030; • Minimize impacts to customer bills; • Ensure system and local reliability; • Strengthen the diversity, sustainability, and resilience of the bulk transmission, distribution systems and local communities; • Enhance distribution systems and demand-side energy management; • Minimize localized air pollutants and other greenhouse gas emissions with early priority to disadvantaged communities; and • Address the following procurement topics: o Energy efficiency and demand resources that are cost effective, reliable and feasible; o Energy storage; o Transportation electrification; o A diversified procurement portfolio of short term electricity, long term electricity, and demand response products; and o Resource adequacy capacity. The EIRP report presented as Attachment A satisfies all of the above statutory requirements. And, it is worthy to note, Palo Alto has already exceeded the state’s 2030 goals of sourcing 50% of electricity supplies from renewable resource and reducing greenhouse gas emissions by 40%—which are the primary drivers of the IRP requirement in the first place. DISCUSSION An IRP represents a snapshot of a continuously evolving and transforming process, as the conditions and circumstances in which utilities make planning and procurement decisions are ever-changing. The IRP process utilizes a methodology and framework for assessing a utility’s shifting business and operating requirements and adapting to factors such as changing technology, regulations, and customer behavior and preferences. Assumptions, scenarios, and results are all reviewed and updated as information and events unfold, and the process is continually revisited. Proposed Work Plan As described in detail in the EIRP, Palo Alto faces a wide range of uncertainties in the course of the EIRP planning horizon. In particular, there is significant uncertainty around the costs and Portfolio Standard (RPS) to meet 50% of the City’s load from applicable renewable supplies by 2030. The 10-Year Energy Efficiency Potential Plan approved by Council in March 2017 addresses the new energy efficiency savings requirements, while the City expects to achieve an RPS of 59% in 2018. Page 5 of 7 generation levels associated with the Western hydro resource, and around the magnitude and shape of the City’s customer load. As such, and as part of the process of revisiting the assumptions and analysis described in the EIRP, staff developed a proposed work plan describing ongoing activities and new initiatives, along with timelines for completing these initiatives, to be undertaken as a means to mitigate the uncertainties mentioned above. The new initiatives identified in the proposed work plan (Attachment C) and associated timelines are summarized below. Summary of New Work Plan Initiatives Timeline 1. Western Contract Decision: Evaluate the merits of committing to a new 30-year contract with Western starting in 2025 • Recommendation on initial commitment to the Western contract • Recommendation on final commitment to the Western contract - Early 2020 - Early 2024 2. Portfolio Rebalancing Analysis: Evaluate the merits of rebalancing the electric supply portfolio to lower seasonal and daily market price exposure by more closely matching the City’s hourly and monthly electric loads – Initial scoping assessment report - Dec 2019 3. COTP decision – Evaluate how to best utilize the City’s share of the California- Oregon Transmission Project (COTP), when the long-term layoff of this asset ends in 2024 – Initial assessment report in tandem with Initiative #2 report - Dec 2019 4. DER Plan – Finalize the Distributed Energy Resource and Customer Program Plan for approval - June 2019 5. Carbon accounting – Evaluate the carbon content of the electric portfolio on an hourly basis, and discuss the merits of buying carbon offsets to ensure the carbon content of the cumulative hourly portfolio is zero on an annual basis – Initial staff recommendation - Dec 2019 6. RPS compliance strategy review – Investigate the merits of monetizing excess RECs to minimize the cost of maintaining an RPS compliant and carbon neutral electricity supply portfolio – Initial staff recommendation - Dec 2019 7. Partner with external agencies – Explore greater synergistic opportunities with NCPA and other agencies to lower Palo Alto’s operating costs – Initial assessment report - Dec 2019 8. Competitive assessment and load uncertainties – Undertake a competitive assessment for the electric utility within the context of the large proliferation of customer-sited DER technologies, and develop contingencies to address the potential for large changes in the City’s load level or load profile – Initial assessment report. - Dec 2020 It should be noted that many of the new initiatives listed above have the same projected completion date. This is intentional, and it is due to the fact that many of these initiatives are highly interrelated: a decision related to the City’s RPS compliance strategy, or carbon accounting methodology, or Western contract renewal, or portfolio rebalancing will impact all of the others. As such, rather than independent reports for each initiative listed, staff may present to the UAC a series of reports that address several of these areas at once. Page 6 of 7 In addition to these new initiatives, staff will continue its activities in pursuit of lowering the overall cost to serve load (and addressing the tradeoffs – which the UAC noted at the June 2018 meeting – between pursuing “green” supply resources and lowering supply costs). These include continuing to optimize the use of the City’s Calaveras resource, and evaluating the benefits of the NCPA pool and/or the procurement of alternative scheduling services for its renewable resources. NEXT STEPS Staff plans to present the final EIRP report (and associated documents) to the UAC and the Finance Committee in October and to the City Council in November. Under state law, final approval of the EIRP report is required by January 1, 2019. Once approved, staff will begin executing the tasks listed in the Work Plan, and will provide the UAC with updates on the progress, successes, and new challenges over the implementation period of this IRP. RESOURCE IMPACT Using existing staffing resources, staff expects to devote approximately 0.75 to 1.5 FTE in the coming years to pursuing elements associated with the Work Plan, including investigating strategies to rebalance the electric portfolio to meet the challenges of the coming decades. In addition, staff has access to a wide pool of resources through NCPA to assist with the new initiatives listed in Attachment C. The 2025 Western contract decision, in particular, is a complex and highly important matter, and staff may seek external consulting and legal assistance to augment NCPA’s resources and services, as well as those of the City Attorney’s office. The cost of such external resources may amount to $100,000 to $200,000 over the next few years. POLICY IMPLICATIONS The EIRP report, Objective and Strategies, and work plan are in line with the Utilities Strategic Plan mission and strategic direction. Specifically, the EIRP report itself was contemplated under Strategy 4, Action 5, of the Financial Efficiency and Resource Optimization Priority of the Utilities 2018 Strategic Plan. These EIRP documents are also in line with the Sustainability and Climate Action Plan goals of continuing to lower the carbon footprint of the community. ENVIRONMENTAL REVIEW The Utilities Advisory Commission’s review and recommendation to Council on the 2018 EIRP report does not meet the definition of a project under Public Resources Code 21065 and therefore California Environmental Quality Act (CEQA) review is not required. ATTACHMENTS A. 2018 Electric Integrated Resource Plan Executive Summary B. Electric Integrated Resource Plan Objective and Strategies C. Electric Integrated Resource Plan Work Plan D. Excerpts of the UAC Meeting Minutes from 06/06/2018 PREPARED BY: JIM STACK, Senior Resource Planner SHIVA SWAMINATHAN, Senior Resource Planner LENA PERKINS, Resource Planner REVIEWED Y: APPROVED BY: JON MAN ABENDSCHEIN, Assistant Director, Resource Management ED SHIA A General Manager of pities Page 7 of 7 Attachment A City of Palo Alto 2018 Electric Integrated Resource Plan C TY OF DRAFT VERSION 1 August 2018 Table of Contents Executive Summary 3 CEC IRP Guidelines & Required Elements 5 Public Process Summary 6 Background & Achievements to Date 7 CPAU History and Mission Statement 7 Previous IRPs & Recent Accomplishments 7 Changing Planning Environment 8 Increasing DER Penetration & Load Profile Uncertainty 9 GHG Emission Reductions 10 Renewable Portfolio Standards (RPS) 10 Energy Efficiency 11 Overview of EIRP methodology 11 Energy and Peak Demand Forecast 12 Forecast methodology and assumptions 12 Palo Alto Energy Model 13 Palo Alto Peak Demand Model 13 Forecasts of Distributed Energy Resources 13 Energy Efficiency Forecast 15 Committed Energy Efficiency 15 Additional Achievable Energy Efficiency 16 Solar Photovoltaic Forecast 16 Transportation Electrification Forecast 16 Energy Storage Forecast 16 Demand Response Forecast 17 Electrification of Space and Water Heating Forecast 17 SB 338 Requirements 17 Existing Resource Portfolio 18 Hydroelectric Resources 19 Western Base Resource 19 Calaveras 21 Renewable Energy Resources 22 Wind PPAs 22 LFG PPAs 22 Solar PPAs 23 Market Purchases & RECs 23 COBUG 24 California -Oregon Transmission Project (COTP) 24 Resource Adequacy Capacity 24 Future Procurement Needs and Portfolio Rebalancing 25 Needs Assessment: Energy, RPS, Resource Adequacy Capacity 25 Portfolio Rebalancing Analysis 25 Portfolio Expected Net Value 28 Portfolio Fit 29 Portfolio Cost Uncertainty and Management 30 Supply Costs & Retail Rates 31 Transmission & Distribution 31 Disadvantaged Communities 32 Low-income Assistance Programs 32 Localized Air Pollutants 33 Electric Vehicle Programs 33 Local Renewable Energy Programs 33 Electrification of Space and Water Heating Programs 34 Path Forward & Next Steps 34 Recommended Portfolio 34 GHG Emissions 35 Next Steps 36 Key Issues to Monitor & Attempt to Influence 37 Supplemental Information 37 1. EIRP Objective and Strategies 2. Load Forecast Methodology and Assumptions 3. Distributed Energy Resources Plan 4. Energy Storage Assessment Report 5. RPS Procurement Plan 6. RPS Enforcement Program 7. CEC IRP Standardized Tables Executive Summary The City of Palo Alto's 2018 Electric Integrated Resource Plan (EIRP) is a comprehensive plan for developing a portfolio of electric power supply resources to meet the utility's objective of providing safe, reliable, environmentally sustainable, and cost-effective electricity services while addressing the substantial risks and uncertainties inherent in the electric utility business. The EIRP also supports the City's mission to promote and sustain a superior quality of life in Palo Alto. In partnership with our community, our goal is to deliver cost-effective services in a personal, responsive and innovative manner. The EIRP meets the requirements of California Senate Bill (SB) 350 (de Leon, Chapter 547, Statutes of 2015), which requires publicly owned utilities (POUs) with an average annual energy load greater than 700 gigawatt-hours (GWh) to submit an IRP at least every five years to the California Energy Commission (CEC). The EIRP discusses current and anticipated California regulatory and policy changes facing Palo Alto and the electric utility industry. Additionally, the IRP presents the analyses conducted and underlying assumptions, and outlines a resource plan to reliably and affordably meet customers' energy needs through calendar year 2030. The electric utility industry has undergone significant changes since Palo Alto prepared its last Long-term Electric Acquisition Plan (LEAP) update in 2012, with a major shift underway towards greater levels of variable, distributed, low -emissions generation, along with an expanding suite of regulatory mandates that the City must satisfy. Table 1 provides an overview of some of the key structural changes in California's electricity market that must be addressed in the 2018 EIRP, compared to their status at the time of the 2012 LEAP update. Table 1: California Energy Market Changes since 2012 LEAP Update GHG Emissions Targets Statewide emissions reduced to 1990 levels by 2020 40% below 1990 levels by 2030 Cap and Trade Renewable Procurement Authorized through 2020 33% by 2020 and beyond Authorized though 2030 50% by 2030 and beyond Distributed Generation Modest growth High growth Energy Efficiency Utility -specific targets (all cost- effective energy efficiency) Statewide goal of doubling energy efficiency savings by 2030 Energy Storage No explicit requirement Requirement to study adoption of targets Transportation Electrification No explicit requirement Requirement to address procurement of EV infrastructure Structured Markets Hourly market Intra-hour market Resource Adequacy Local and system capacity requirements Local, system, and flexible capacity requirements Similarly, Palo Alto itself has undergone a myriad of changes over the past six years —both in its long-term planning goals and in how it uses electricity currently. Table 2 describes some of the major changes and accomplishments in Palo Alto since 2012, from dramatic changes in the City's power supply and emissions reduction targets, to considerable growth in local solar generation and electric vehicles (EVs). Table 2: City of Palo Alto Energy -Related Changes since 2012 LEAP Update Community -wide GHG Emissions Goals (from electricity, natural gas and transportation) Goal: Reduce GHG emissions to 1990 levels by 2020 (^'15% reduction from 2005 levels). Electric Supply Portfolio Goals 33% RPS by 2015 Achieved 43% reduction below 1990 emission levels in 2017; goal of 80% reduction by 2030. 100% carbon neutral supplies Electric Supply Portfolio Status 2012 RPS level: 21% 2017 RPS level: 57% Local Solar PV Systems 502 systems (meeting 0.57% of community electric load) 1,081 systems (1.94% of load); Goal of 4% of electric loads to be served by local Solar PV by 2023 Energy Efficiency Annual goal of 0.6% and 10 - year cumulative savings goal of 4.8%1 (2014-2023) Achieved 6 -year cumulative savings of 3.4% (2012-2017); For 2018-2027, Annual goal of 0.75% and 10 -year cumulative savings goal of 5.7% Energy Storage No explicit goals No explicit goals or rebates; found to be not cost-effective. Facilitate customer adoption in coordination with Buildings department. Transportation Electrification 200 EVs estimated to be registered in Palo Alto ^'3,000 EVs registered in Palo Alto (early 2018). Incentives for EV charger installations; 60 public EV chargers owned and maintained by the City. Annual Energy Load 972 GWh 925 GWh (^'5% reduction) Summer Peak Capacity Load 170 MW 182 MW in 2017 (hot summer) Average Retail Rate2 11.6 cents/kWh 13.9 cents/kWh The EIRP planning period is from 2018 to 2030. Through 2028, the City of Palo Alto Utilities (CPAU) has sufficient renewable contracts to supply over 50% of the City's annual electrical energy needs. The City's first long-term renewable contract —for wind power —expires at the end of 2021 and the other wind contract and all five landfill -gas -to energy contracts expire in 1 Note: Annual savings estimates degrade each year when computing cumulative saving estimates. 2 Retail rate values in Table 2 are for Fiscal Years 2012 and 2018; the rest of the values are for Calendar Years 2012 and 2018. the late 2020's or early 2030's, while the solar contracts all extend beyond 2040. The City's contract with the Western Area Power Administration (WAPA) for hydroelectric resources, which supplies nearly 40% of the City's energy needs in a normal hydro year, expires at the end of 2024. A major consideration for the EIRP is whether to renew the contract with WAPA (and if so, at what participation level) and/or seek other renewable supplies. CPAU expects to continue operating within the Northern California Power Agency's (NCPA) Metered Sub -System A;regation (MSSA) Agreement with the California Independent System Operator (CAISO). Under this agreement, NCPA balances CPAU's loads and resources to comply with CAISO planning and operating protocols. With resources available under the NCPA MSSA Agreement, Palo Alto has access to sufficient system, local, and flexible capacity, as well as resources to provide ancillary services to reliably meet City loads. Costs are projected to increase through 2030, primarily due to system upgrade costs, increasing environmental regulations, and renewable integration costs (which are part of the tradeoff between pursuing sustainable electricity supplies and reducing overall supply costs). Costs are increasing, but retail energy sales are decreasing due to increases in energy efficiency and local solar installations, and are further expected to decline in 2020 and beyond due to building codes mandating new homes be net zero annual energy. Part of this reduction in electrical energy use is expected to be offset by higher penetration of electric vehicles and electrification of natural gas appliances. CPAU staff will provide public updates on the progress, successes, and new challenges over the implementation period of this IRP. CEC / P Guidelines equired Ele eats The schedule and structure of the EIRP process is being guided in large part by requirements imposed by SB 350,3 which states that Palo Alto's IRP must be adopted by Council by January 1, 2019, submitted to the CEC by April 30, 2019, and updated at least once every five years thereafter. At a minimum, Sections 9621 and 454.52 of the State Public Utilities Code require that the City's IRP will need to: • Ensure procurement of at least 50 percent renewable resources by 2030 • Meet Palo Alto's share of the greenhouse gas emission reduction targets established by the California Air Resources Board (CARB) for the electricity sector, to enable California to achieve the economy wide greenhouse gas emissions reductions of 40 percent from 1990 levels by 2030 • Minimize impacts to customer bills • Ensure system and local reliability Strengthen the diversity, sustainability, and resilience of the bulk transmission, distribution systems and local communities 3 S 350 also requires the doubling of energy efficiency savings targets by 2030 and establishes a new Renewable Portfolio Standard (RPS) to meet 50% of the City's load from applicable renewable supplies by 2030. The 10 -Year Energy Efficiency Potential Plan approved by Council in March 2017 addresses the new energy efficiency savings requirements and the City expects to achieve an RPS of 57% in 2018. • Enhance distribution systems and demand -side energy management Minimize localized air pollutants and other greenhouse gas emissions with early priority to disadvantaged communities Address the following procurement topics: o Energy efficiency and demand resources that are cost effective, reliable and feasible o Energy storage o Transportation electrification o A diversified procurement portfolio of short term electricity, long term electricity, and demand response products o Resource adequacy The City currently has the resources and systems in place needed to achieve all of the objectives addressed by these IRP requirements. In addition, CPAU is submitting the following four Standardized Tables as part of the EIRP: Capacity Resource Accounting Table (CRAT): Annual peak capacity demand in each year and the contribution of each energy resource (capacity) in the POU's portfolio to meet that demand. Energy Balance Table (EBT): Annual total energy demand and annual estimates for energy supply from various, resources. RPS Procurement Table (RPT): A detailed summary of a POU resource plan to meet the RPS requirements. GHG Emissions Accounting Table (GEAT): Annual GHG emissions associated with each resource in the POU's portfolio to demonstrate compliance with the GHG emissions reduction targets established by the California Air Resources Board (CARB). The four Standardized Tables for Palo Alto's IRP require complete data for calendar year 2018, and will be submitted prior to the April 30, 2019 due date, once this data is available. However, draft versions based on current supply projections are provided as attachments. This EIRP document, along with the four aforementioned Standardized Tables and the materials listed in the Supporting Information section satisfy the IRP filing guidelines listed in Chapter 2 of the CEC guidelines. tic rocess Su ary Palo Alto staff has provided numerous reports and presentation related to various facets of the EIRP to the Utilities Advisory Commission (UAC) over the past 15 months. The current EIRP report is scheduled to be reviewed by the UAC on September 5, 2018, before being presented to the Finance Committee and City Council for approval in October and November 2018, respectively. Table 3 below lists all public presentations related to the EIRP, with links to the associated reports and webcasts. Table 3: Public Process Summary for Development of the 2018 EIRP Forum Date Topic Link UAC 6/7/2017 Overview of CPAU’s EIRP Development Process Report UAC 8/2/2017 Discussion of DER Plan Development Report UAC 8/2/2017 Discussion of California Wholesale Energy Market and Electric Portfolio Cost Drivers Report UAC 9/6/2017 Discussion of Hydroelectric Resources and Carbon Neutral Portfolio Alternatives Report UAC 11/1/2017 Discussion of Proposed DER Plan Report UAC 12/6/2017 Discussion of Renewable and Carbon Neutral Portfolio Strategy Report UAC 4/12/2018 Assessment of CPAU’s Distribution System to Integrate DERs Report UAC & Council 5/2/18 & 5/21/2018 CPAU Demand Side Management Annual Report – FY 17 UAC, Council UAC 6/6/2018 Long-term Electric Portfolio Analysis Results and Options for Rebalancing Portfolio in the Next Five to Ten Years Report UAC 9/5/2018 CPAU’s 2018 EIRP Executive Summary, Objective & Strategies, and Work Plan N/A An IRP represents a snapshot of an iterative process that evolves and transforms over time. The conditions and circumstances in which utilities must make decisions about how to meet customers’ future electric energy needs are ever-changing. The IRP process utilizes a methodology and framework for assessing a utility’s ever-changing business and operating requirements and adapting to factors such as changing technology, regulations, and customer behavior. Assumptions, scenarios, and results are all reviewed and updated as information and events unfold, and the process is continually revisited under formal or informal resource planning efforts. 6055046 Electric Integrated Resource Plan (EIRP) Objective and Strategies EIRP Objective To provide safe, reliable, environmentally sustainable and cost-effective electric resources and services to all customers. EIRP Strategies 1. Pursue an Optimal Mix of Supply-side and Demand-side Resources: When procuring to meet demand, pursue an optimal mix of resources that meets the EIRP Objective, with cost-effective energy efficiency, distributed generation, and demand-side resources as preferred resources. Consider portfolio fit and resource uncertainties when evaluating cost-effectiveness. 2. Maintain a Carbon Neutral Supply: Maintain a carbon neutral electric supply portfolio to meet the community’s greenhouse gas (GHG) emission reduction goals. 3. Actively Manage Portfolio Supply Cost Uncertainties: Structure the portfolio or add mitigations to manage short-term risks (e.g. market price risk and hydroelectric variability) and build flexibility into the portfolio to address long-term risks (e.g. resource availability, customer load profile changes, and regulatory uncertainty) through diversification of suppliers, contract terms, and resource types. 4. Manage Electric Portfolio to Ensure Lowest Possible Ratepayer Bills: Pursue resources in a least-cost, best-fit approach in an effort to ensure ratepayer bills remain as low as possible, while achieving other Council-adopted sustainability, rate, and financial objectives. 5. Partner with External Agencies to Implement Optimization Opportunities: Actively engage and partner with external agencies to maximize resource value and optimize operations. 6. Manage Supplies to Meet Changing Customer Loads and Load Profiles: Maintain electric supply resource flexibility in anticipation of potential changes in customer loads due to distributed energy resources, efficiency, electrification, or for other reasons. At the same time, use retail rates and other available tools to influence customer load changes in a manner that minimizes overall costs and achieves other Council objectives. 7. Ensure Reliable and Low-cost Transmission Services: Work with the transmission system operator to receive reliable service in a least-cost manner. 8. Support Local Electric Supply Resiliency: Coordinate supply portfolio planning with utility-wide efforts to support local measures and programs that enhance community electric supply resiliency. 9. Comply with State and Federal Laws and Regulations: Ensure compliance with all statutory and regulatory requirements for energy, capacity, reserves, GHG emissions, distributed energy resources, efficiency goals, resource planning, and related initiatives. Attachment B EIRP Strategies & Related New Initiatives There are a number of new initiatives and numerous on-going tasks related to implementing the EIRP Strategies. These activities are supported by about six to eight CPAU staff, both from the supply side and demand-side (or customer) programs. In addition, CPAU relies on joint action agencies and external service providers to implement programs and initiatives. Supply and customer program staff also coordinates with retail rate development, distribution system engineering, and operations staff to implement programs and investments in an integrated manner. Described below are the nine strategies and eight new initiatives that are expected to be undertaken in the next three to six years. Work tasks related to on-going activities have not been called out separately. EIRP Strategies & Related New Initiatives 1. Pursue an Optimal Mix of Supply-side and Demand-side Resources: When procuring to meet demand, pursue an optimal mix of resources that meets the EIRP Objective, with cost-effective energy efficiency, distributed generation, and demand-side resources as preferred resources. Consider portfolio fit and resource uncertainties when evaluating cost-effectiveness. a. Initiative #1: Evaluate the merits of committing to a new 30-year contract with Western starting in 2025. [Recommendation on initial commitment to the UAC in early 2020; recommendation on final commitment in early 2024.] b. Initiative #2: Evaluate the merits of rebalancing the electric supply portfolio to lower its seasonal and daily market price exposure, by more closely balancing the City’s long-term supplies with its hourly and monthly electric loads. [Initial scoping assessment report to the UAC by December 2019.] c. Initiative #3: Evaluate how to best utilize the City’s share of the California- Oregon Transmission Project (COTP), when the long-term layoff of this asset ends in 2024. [Initial assessment report to UAC by December 2019, in tandem with Initiative #2 initial scoping assessment report.] d. Continue ongoing evaluation of all cost-effective distributed energy resources (DERs), such as energy efficiency, distributed generation, energy storage, and demand response. Update forecasts of DER impacts on retail sales and load shapes for use in strategic planning, rate-making, and budget forecasting. [Initial assessment to be completed in Distributed Energy Resource (DER) and Customer Program Plan for Council approval by June 2019.] 2. Maintain a Carbon Neutral Supply: Maintain a carbon neutral electric supply portfolio to meet the community’s greenhouse gas (GHG) emission reduction goals. a. Initiative #4: In addition to ensuring 100% of City’s annual electricity energy needs are met with carbon neutral supplies (on a kWh basis), evaluate the carbon content of the electric portfolio on an hourly basis, and recommend the merits of buying carbon offsets to ensure the carbon content of the cumulative Attachment C hourly portfolio is zero on an annual basis. [Initial staff recommendation to the UAC by December 2019.] 3. Actively Manage Portfolio Supply Cost Uncertainties: Structure the portfolio or add mitigations to manage short-term risks (e.g. market price risk and hydroelectric variability) and build flexibility into the portfolio to address long-term risks (e.g. resource availability, customer load profile changes, and regulatory uncertainty) through diversification of suppliers, contract terms, and resource types. a. This is an on-going active management strategy; no new initiatives are planned. 4. Manage Electric Portfolio to Ensure Lowest Possible Ratepayer Bills: Pursue resources in a least-cost, best-fit approach in an effort to ensure ratepayer bills remain as low as possible, while achieving other Council-adopted sustainability, rate, and financial objectives. a. Initiative #5: Investigate the merits and economics of monetizing excess renewable energy certificates to minimize the cost of maintaining an RPS compliant and carbon neutral electricity supply portfolio. [Initial staff recommendation to the UAC by December 2019.] 5. Partner with External Agencies to Implement Optimization Opportunities: Actively engage and partner with external agencies to maximize resource value and optimize operations. a. Initiative #6: Explore greater synergistic opportunities with NCPA and other agencies – such as newly formed community choice aggregators – to lower Palo Alto’s operating costs and rebalance the supply portfolio. [Initial assessment to UAC by December 2019.] 6. Manage Supplies to Meet Changing Customer Loads and Load Profiles: Maintain electric supply resource flexibility in anticipation of potential changes in customer loads due to distributed energy resources, efficiency, electrification, or for other reasons. At the same time, use retail rates and other available tools to influence customer load changes in a manner that minimizes overall costs and achieves other Council objectives. a. Initiative #7: Implement 2018 Utilities Strategic Plan Priority 4, Strategy 4, Action 2 by undertaking a competitive assessment for the electric utility within the context of the large proliferation of customer-sited DER technologies, electrification initiatives, changing customer expectations, and potential regulatory changes. Develop contingencies to address the potential for large changes in the City’s load level or load profile. [Initial assessment to UAC in December 2020.] 7. Ensure Reliable and Low-cost Transmission Services: Work with the transmission system operator to receive reliable service in a least-cost manner. a. This is an on-going activity; no new initiatives are planned. 8. Support Local Electric Supply Resiliency: Coordinate supply portfolio planning with utility-wide efforts to support local measures and programs that enhance community electric supply resiliency. a. On-going supporting role in utility-wide efforts. 9. Comply with State and Federal Laws and Regulations: Ensure compliance with all statutory and regulatory requirements for energy, capacity, reserves, GHG emissions, distributed energy resources, efficiency goals, resource planning, and related initiatives. a. Ongoing activities in collaboration with NCPA, CMUA and other joint action agencies. EXCERPTS OF UTILITIES ADVISORY COMMISSION MEETING MINUTES OF JUNE 6, 2018 REGULAR MEETING ITEM 3. DISCUSSION: Long-Term Electric Portfolio Analysis Results and Options for Rebalancing Portfolio in the Next Five to Ten Years. Shiva Swaminathan, Senior Resources Planner, reported that every five years staff develops criteria to plan and execute portfolio management. Utilities are required to file their Electric Integrated Resource Plans (EIRP) with the California Energy Commission. The Utility's contract with Western for hydroelectricity will expire in 2024. Staff requests Commissioners' input regarding the summary of findings and the EIRP objective and strategies. Based on UAC input, staff will return with a revised EIRP objective and strategies, EIRP regulatory documents, and a work plan for proceeding over the next 3-5 years. Commissioner Ballantine appreciated the analysis of each portfolio option from a number of perspectives. With the analysis of data, Commissioners can decide how to handle the implications. Commissioner Segal noted the inherent conflict in the list of EIRP objectives. She questioned whether staff had obtained community input regarding tradeoffs the community is willing to make. Community input is needed to evaluate priorities. EIRP Strategy Number 8 has to be number one because the Utility has to comply with laws. Swaminathan advised that the Council set a premium of no greater than 0.5¢ per kWh when adopting the Renewable Portfolio Standard (RPS) and the Carbon Neutral Plan. Staff achieved the Carbon Neutral Plan with a premium of 0.1¢-0.2¢ per kWh. Now, the decision is how to optimize within the established premium. In December, the UAC suggested Staff focus on minimizing costs while maintaining the RPS and carbon-neutral goals. As to an inherent conflict, staff can present it and the rate impact for discussion. Vice Chair Schwartz believed tradeoffs were not well understood. The Utility could not be greener than all other electric utilities and have the lowest prices of any electric utility. Councilmember Filseth could assist the UAC with presenting tradeoffs to the Council so that they understand them. The priorities in the community may not align fully with the priorities of the City Council or the UAC. If people really want the least expensive electric cost, they need to understand that buying Renewable Energy Certificates (RECs) is not the solution. Commissioners need to know the tradeoffs in order to make recommendations to the City Council for direction to staff. Councilmember Filseth agreed that the City Council and the general public need to understand the meaning of tradeoffs. Commissioner Trumbull commented that the community does not want to be minimally compliant. The UAC has to sell the notion that being the greenest and the cheapest utility is difficult. In response to Commissioner Trumbull's query regarding the Utility's compliance with regulatory requirements, Swaminathan advised that the Utility is compliant with regulations. In answer to Vice Chair Schwartz’s question regarding the amounts of market power purchases and RECs in the electric supply mix, Jonathan Abendschein, Assistant Director of Utilities Resource Management, explained that the Utility purchased RECs a few years back when the Utility had a deficit from long-term Power Purchase Agreements. The Utility has surpluses from long-term resources that are sold in the Attachment D summer. In the winter, the Utility has a deficit and brown power is purchased. Commissioner Ballantine remarked that the Utility net meters at a macro scale. In reply to Vice Chair Schwartz's inquiry regarding the purchase of market power in 2020, Swaminathan reported the Utility was not planning to purchase any RECs. In answer to Councilmember Filseth's query about the CO2 emitted into the atmosphere over a one-year cycle, Commissioner Ballantine responded the amount is 17% because nighttime power is browner than daytime power. Swaminathan referred to Tables C-1 and C-2 and stated the surplus of 263 GWh of energy displaces 63,000 metric tons of CO2 per year while the deficit of 201 GWh of energy adds 68,000 metric tons. The net amount of CO2 is 4,800 metric tons. Total City emissions are approximately 500,000 metric tons; therefore, CO2 emissions from electricity represent approximately 1% of the total. In response to Commissioner Ballantine's question regarding potential biogas generation at the City’s landfill, Swaminathan explained that staff analyzed a multipurpose project years before, but it did not pencil out. Abendschein reported legislative and regulatory discussions were underway regarding reporting information on the power content label and counting the carbon in an electric portfolio. Before discussing any changes to the electric portfolio based on carbon emissions, staff wanted to wait for those discussions to unfold. The UAC would have at least two additional meetings to discuss this in more detail. Staff would present a policy discussion of tradeoffs in early 2019. Commissioner Segal requested staff notify the UAC when the Council's adopted limit on bill impacts related to the Carbon Neutral Portfolio becomes a barrier. ACTION: No action Page 1 of 2 2 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILTIES DEPARTMENT DATE: September 5, 2018 SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend that Council Accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan, Including Advanced Metering Infrastructure- Based Smart Grid Systems to Serve Electricity, Water, and Natural Gas Utility Customers RECOMMENDATION Staff requests that the Utilities Advisory Commission (UAC) recommend that the City Council accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan (Utilities Technology Plan), including the estimated timeline and resources for the implementation of an Advanced Metering Infrastructure (AMI)-based smart grid system to more effectively serve electricity, natural gas and water utility customers. EXECUTIVE SUMMARY Staff presented a report on this topic at the May 2, 2018 UAC meeting (Attachment A). Commissioners discussed the staff and consultant reports and were in agreement with staff’s recommendation (Attachment A), but deferred voting on the recommendation until they fully reviewed the consultant report. Staff expects the UAC to continue discuss outstanding topics they may have from the May discussion and to vote on the recommendation at this meeting. NEXT STEPS Pending UAC consideration and recommendation, staff will seek approval from Council. A tentative capital budget of $1,000,000 was included in the FY19 budget. This report is expected to come to Finance Committee in October and Council in December for approval. If approved, consultants would be retained to assist with Phase II - AMI system specifications and vendor proposal evaluation (2019-20). Phase III - AMI vendor contracting and implementation (2020- 22) which will require subsequent Council approvals. RESOURCE IMPACT The costs of these investments have been included in the proposed FY 2019 Capital Budget (Project EL-11014). The funding for the next five years are outlined below. Page 2 of 2 ATTACHMENTS •Attachment A: UAC Report on Smart Grid Assessment & Utilities Technology Plan: May 2, 2018 •Attachment B: Excerpts of the UAC Meeting Discussions on May 2, 2018 PREPARED BY: SHIVA SWAMINATHAN, Senior Resource Planner DAVE YUAN, Utilities Strategic Business Manager REVIEWED BY: TOM AUZENNE, Assistant Director, Customer Support Services DEAN BATCHELOR, Utilities Chief Operating officer JONATHAN ABENDSCHEIN, Assistant Director, Resource Management APPROVED BY: _____________________________________ ED SHIKADA General Manager of Utilities Capital Budget Projections for AMI Project Electric Gas Water Total FY 2019 0.53 0.18 0.29 1.00 FY 2020 0.00 0.00 0.00 0.00 FY 2021 1.59 0.54 0.87 3.00 FY 2022 5.30 1.80 2.90 10.00 FY 2023 2.65 0.90 1.45 5.00 Total 10.07 3.42 5.51 19.00 Page 1 of 17 1 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILTIES DEPARTMENT DATE: May 2, 2018 SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend that Council Accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan, Including Advanced Metering Infrastructure- Based Smart Grid Systems to Serve Electricity, Water, and Natural Gas Utility Customers RECOMMENDATION Staff requests that the Utilities Advisory Commission (UAC) recommend that the City Council accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan (Utilities Technology Plan), including the timeline and resources for the implementation of an Advanced Metering Infrastructure (AMI)-based smart grid system to more effectively serve electricity, natural gas and water utility customers. EXECUTIVE SUMMARY City of Palo Alto Utilities Department (CPAU) staff, along with consultants, developed a strategic technology roadmap over a five-year horizon and identified major critical technology investments such as a replacement for the utilities customer information and billing system (CIS), deployment of AMI, and in coordination with the City’s IT department, the implementation of a new citywide enterprise resource planning system (ERP). All of these projects require significant planning, financial and staffing resources and system integration. To ensure a successful AMI deployment, the new CIS system must be stable before integrating with the AMI system. The Utilities Technology Implementation Plan sets out a coordinated implementation approach for these projects. AMI is a foundational technology that will improve customer experience and enable CPAU to operate more effectively, and is becoming a standard in the utilities industry. An AMI-based smart grid system will empower customers to more efficiently utilize utility supplies, facilitate customer adoption of distributed energy resources (DER) such as solar photovoltaics (PV) and electric vehicles (EV), and enable more efficient detection of water leaks. AMI will also enable CPAU to optimize operations and improve reliability by reducing time to restore outages. Given the large investments required to implement an AMI system, a cost-benefit analysis was undertaken to determine financial viability of AMI, and assess staffing requirements, technological dependencies, project risks, and CPAU’s operational readiness. ATTACHMENT A Page 2 of 17 The consultant found that the overall net-present-value (NPV) of the investment over the 18- year life of the system was close to break-even,1 considering only the costs and benefits that can be quantified. This effectively means that there will be little or no impact on utility cost to customers over the 18-year life of the project. Upon including non-quantifiable benefits such as enhanced customer experience, improved system reliability, and better distribution asset utilization, the analysis suggests that this strategic investment would be a net benefit to all utility customers, particularly for the electricity and water utility customers. The estimated capital cost related to the AMI system installation is $16 to 18 million 2 with an investment life of 18 years. An additional $1.5 million to $2 million in internal staffing-related costs will also need to be allocated to implement the project. The evaluation also analyzed the operational impact and found that the investment will require a number of staffing changes to implement and maintain the AMI infrastructure to maximize the value of the investment. The annual operating cost of the AMI system is estimated to be $1.9 million, which would be offset by $3.3 million in benefits, resulting in the net benefit of $1.4 million per year on an ongoing basis. The allocation of the $19 million in initial capital and staffing costs among the three utility funds is expected to be as follows: Electric Fund ($10M), Water Fund ($5.5M) and Gas Fund ($3.5M). The Electric Special Projects (ESP) is available to fund the electric portion of the investment, which eliminates the need for rate changes in the Electric Fund. The Gas and Water Funds will cover the up-front costs from reserves rates, and may consider financing options as well to minimize rate impacts. Given the favorable results of the cost-benefit analysis, CPAU staff recommends proceeding with AMI and has included the capital costs of the new AMI system in the Electric, Gas, and Water Utility Financial Plans and the Proposed FY 2019 – FY 2023 Capital Budget. Operational costs (consultant costs and staffing requests) needed to begin work on the CIS, ERP, and AMI projects are included in the FY 2019 budget, and additional staffing to continue the project will be included in subsequent year budgets. Staffing and other operational needs in future years are forecasted in the Utilities Technology Implementation Plan and firm proposals will be submitted in future budget years. 1 See Figure 2. NPV is based on a discount rate of 3.5% over the 18-year life of the project. However, the NPV could range from negative $14.7 million to positive $7.8 million, depending on possible range of outcomes over the life of the project. The NPV value is highly sensitive to operational staffing synergies that could be achieved and customer energy/water conservation that could be spurred by the AMI investments. If such benefits are not achieved, the annual operational savings will diminish, but are still likely to be positive on an annual on-going basis. 2 This include costs to replace all utility customer electric meters, add radio modules on all existing natural gas and water meters, deploy a mesh network to communicate with the meters, integrate the AMI with CPAU’s Customer Information and Billing system (CIS), provide customers with access to hourly utility consumption patterns and enable customers to more efficiently use utility supplies. This investment will also enable CPAU to have visibility into the utility distribution system network to more optimally manage the system. It should be noted that the cost of replacing aging water and gas meters will continue under the ongoing capital improvement project for meter replacement, and is not included under the AMI budget, but efforts will be coordinated with the AMI project. Page 3 of 17 BACKGROUND In 2012, City of Palo Alto Utilities (CPAU) completed an assessment of smart grid applications based on AMI for Palo Alto. The study estimated the capital cost associated with AMI implementation for electric, natural gas and water utility services at $15 million to $20 million, and the cost-benefit assessments found the costs outweighed benefits over the 15 year to 20 year life of such an investment. Based on these findings, the study recommended, and City Council approved, deferring major investments in smart grid for several years until technologies mature and implementation costs decline. While deferring the investment, Council also approved a number of pilot scale smart grid projects to evaluate Palo Alto-specific applications (Staff Report 3330, 12/10/2012) at a cost of $0.45M over five years. In 2013, the Customer Connect pilot project provided electricity, natural gas and water AMI meters to 300 interested single family residential customers and provided time-of-use electric rates to interested customers, including electric vehicle owners. It also provided the capacity to monitor distribution system voltages. The pilot phase of the program ended in 2017 but staff is planning to maintain the program for current participants until full AMI deployment. A report summarizing the lessons learned and findings from the pilot was discussed with the UAC (UAC Report dated 09/06/2017). During the five year period, staff has also extensively engaged with other utilities that have deployed AMI and learned from their experiences. A CPAU staff team, with cross divisional participation, has also closely collaborated with industry experts and stakeholders to learn about the smart grid technologies and their applications in Palo Alto.3 To implement many of these applications, Palo Alto would need the foundational AMI system in place. DISCUSSION In May 2017, CPAU retained Utiliworks Consulting (UWC) as consultants to re-evaluate the cost and benefits associated with AMI investments and to develop an overarching technology roadmap including an implementation plan (Staff Report 7836, 5/8/2017). The Smart Grid Assessment & Utilities Technology Plan (Attachment A) is the result of the consultant’s efforts. The positive cost-benefit assessment presented in the plan is guiding staff’s recommendation to proceed with AMI investments and the roadmap in the plan will roughly guide staff’s activities and proposals to Council over the next five years. Staff is asking the UAC to recommend that Council accept this report and approve its use as a high-level roadmap for AMI-related activities over the next five years, with the understanding that various parts of the plan (such as budgets and staffing actions) would require separate and additional approval by Council at the appropriate time, with modification as needed. The financial and staffing impacts are summarized in the Resource Impact section. 3 Palo Alto is a member of Smart Electric Power Association, NCPA Smart Grid Group, Bay Area Water AMI Group, California Electric Transportation Coalition, Building Decarbonization Working group; and participates in forums hosted by EPRI, Emerging Technology Coordinating Council, CEC/EPIC forum, California Energy Storage Alliance, and regional conferences. Through CPAU’s Emerging Technology program and engagement through Stanford, staff also engages with technology vendors to find suitable opportunities for Palo Alto. Page 4 of 17 The content of the report is summarized in the following sections: A. Components of AMI Technology and Associated Capital Investment Cost B. AMI System Operating Benefits C. AMI System Operating Cost D. Summary of Cost-Benefit Analysis & Sensitivity Analysis of AMI Investment E. Policies and Procedures to Implement and Operate AMI based Utility System F. Coordinated Implementation with Technology Projects – Technology Roadmap G. Change Management & Staffing Resource Needs H. Community and UAC Input I. AMI Project Implementation/Operating Risks and Risk Mitigation Strategies A. Components of AMI Technology and Associated Capital Investment Cost Implementation of an AMI-based smart grid system will require a number of major components. These major components and their related costs are tabulated below. The total cost of the project is estimated at $18 million to $19 million, which includes costs related to equipment and software purchases, systems integration, contract services and internal staffing requirements. Table 1 lists these cost categories. All of these costs are included in the FY 2019 Proposed Capital Budget that extends through FY 2023. Table 1: Components of AMI Investment Cost (Equipment, Services, Staffing to Implement) AMI Components Purpose Cost ($M) Electric Meters & Installation To record electricity consumption and voltage at customer premises every 15 minutes and make consumption information available to customers the next day.4 $5.5 Radios, dials & installation to mount on existing water meters To record water meter consumption every hour and make consumption information available to customers the next day. $4.2 Radios & installation to mount on existing gas meters To record gas meter consumption every hour and make consumption information available to customers the next day. $2.3 Mesh network radios and meter head-end database Mesh radios to receive and transmit meter readings to the head-end database for storage $0.7 Meter data management System (MDMS) & Integration with billing and customer portal MDMS validates the 15-min interval consumption and voltage reads, estimates missing interval reads through a validation process, and stores the information in a database for utility billing and display on customer web portal $2.7 Meter Installation Services Approximately 73,000 meters and/or radios will be installed and provisioned by third party installers $0.4 4 Real time reads could be made available to customer via the meter’s Zigbee wireless radio, if customer owns a compatible in-home-display (IHD). Page 5 of 17 Project management and software integration services Professional AMI project management consultants would be hired to oversee software integration/testing and coordinate the implementation of the project $0.9 TOTAL COST OF EQUIPMENT AND PROJECT IMPLEMENTATION SERVICES $16.7 Internal CPAU staffing Cost 3-4 FTE staff needed over the 2-3 year period to plan and implement the project $1.5M to $2M ESTIMATED TOTAL PROJECT COST $18M to $19M The equipment and software components of the AMI system and their interfaces with the Meter Data Management (MDM) and CIS systems are illustrated in Figure 1. Figure 1: Illustration of AMI Mesh Network, MDM System, Interface with CIS/Billing System B. AMI System Operating Benefits Electric distribution systems are transitioning away from their original purpose of delivering energy from the utility to the customer. The new distribution system is evolving into a complex network that will allow integration of widely distributed energy generation, storage, and energy management systems owned by customers. The widespread adoption of DER systems 5 by 5 DERs are defined as distributed renewable generation resources such as solar photovoltaics (PV), energy efficiency (EE), energy storage (ES), electric vehicles (EV), and demand response (DR) technologies. The emphasis on customer DER adoption from the State level is because DERs as key enabling technologies to both lower greenhouse gas emissions (GHG) and to help electric grid reliability with increased penetration of intermittent Page 6 of 17 electricity consumers and the increasing reliance on intermittent renewable electric supply resources to lower greenhouse gases associated with the state’s electric supply are fundamentally transforming the way electric utilities operate. These changes will require the utility to implement time-dependent electric customer rates, provide more timely and relevant information to customer about electric consumption patterns, and to gain greater visibility of the electricity flows in the distribution system for reliable utility operations. In addition to meeting these needs of the electric customer and utility, an AMI system could also provide greater visibility of water and natural gas usage for customers. AMI sensors will enable faster detection and repair of water leaks, and provide tools for CPAU and customers to implement additional customer energy efficiency and conservation initiatives. If customers opt to participate in these initiatives, the commensurate reduction in consumption will lower CPAU’s costs to purchase electricity, natural gas and water supplies. Voltage sensing on the electric distribution feeders is estimated to result in 0.5% Conservation Voltage Reduction (CVR) related energy saving. Table 2 provides an estimate of AMI-related conservation savings based on estimates of customer participation after 5 years of AMI implementation. AMI will also largely eliminate the need for manual meter reading function6. The new technology will also largely eliminate the need for manual ‘check-reads’ currently undertaken in the event the manual read is incorrectly entered into the handheld meter reading device. The total AMI related operating benefits are estimated at $3.3 million/year in year 5 after installation. renewable energy supplies. Locally, CPAU considers energy efficiency and demand reduction as the highest priority resource and Palo Alto’s Sustainability and Climate Action Plan (S/CAP) also identified several DERs as key technologies for achieving the community’s greenhouse gas (GHG) emission reduction goals, particularly EVs, high- efficiency heat-pump water heaters (HPWH), and heat-pump space heaters (HPSH) which displace fossil fuel combustion. 6 CPAU is engaged with meter reading staff for them to train and transition to other roles with the City in the 2022 timeline. Page 7 of 17 Table 2: Listing of AMI Related Operating Benefit Estimates ($3.3 million/year) C. AMI System Operating Cost Incremental operating costs related to AMI investments are primarily related to new staffing roles needed to: a) monitor and maintain hardware/software associated with the wireless network established to read advanced meters, b) analyze and utilize the large amounts of data that will become available through the AMI system, and c) optimally operate the electric, gas and water distribution systems. These staffing and other O&M costs are estimated at $1.9 million per year, in year 5 after installation. Cost Category Key Assumptions(s)Annual Benefit (M$) Subtotal 95% reduction on staffing load $ 1.26 Subtotal 12.7% reduction on staffing load $ 0.35 Subtotal 0.5% CVR savings $ 0.47 Subtotal $ - Electric Conservation 0.5% conservation for residential customers, ramping up to 1.5% in 5 years; 0.25% for commercial customers $ 0.38 Water Conservation 1.00% conservation, ramping up to 2.5% in 5 years $ 0.55 Gas Conservation 1.00% conservation, ramping up to 2.0% in 5 years $ 0.26 Subtotal $ 1.19 Subtotal $ - Solar Meter Installation Cost Avoidance 100% reduction $ 0.02 Subtotal $ 0.02 GRAND Total $ 3.30 Asset Management Meter Reading Customer Service & Field Service Operations CVR Savings & Operations Improved Meter Accuracy Customer Conservation Savings & Avoided Purchase Cost Avoided CIP Page 8 of 17 Table 3: Listing of AMI Related Operating Cost ($1.9 million/year) D. Summary of Cost-Benefit Analysis & Sensitivity Analysis of AMI Investment The business case employs a net present value (NPV) analysis methodology to compare the costs with monetized benefits. The NPV approach translates planned annual capital investments, ongoing annual operations and maintenance expenditures, and ongoing annual benefits into today’s dollars. The analysis computed the net present value (NPV) associated with the AMI investment over an 18 year period and found the investment, based on the cost and benefit assumptions shown in Tables 2 and 3 and described in more detail in the consultant’s full report, to be near break- even over the life of the project. The analysis computed present value (PV) of operating cost and operating benefits over an 18 year period, and compared it with the initial capital cost, as shown in Table 4 below. The annual incremental operating cost in Year 5 after project completion was estimated at $ 1.9 million, and the corresponding PV of this cost over 18 years was estimated at $27 million. Similarly, the annual operating benefits associated with the AMI project were estimated at $3.3 million and PV over 18 years was estimated at $43.8 million. If these assumptions prove to be accurate, the resulting PV of net operating benefit of $16.8 million is close to the capital expenditure, making this project near breakeven on a NPV basis. This result is shown in Table 4 and illustrated in Figure 2. Cost Category Annual O&M Cost ($ Million) AMI Network Infrastructure, Software, and Professional Services $ 0.12 MDMS and Professional Services $ 0.23 Subtotal $ 0.34 Staffing $ 0.41 Subtotal $ 0.41 Staffing $ 0.41 Subtotal $ 0.41 Staffing $ 0.64 Subtotal $ 0.64 Staffing & Professional Services $ 0 Subtotal $ 0 GRAND Total $ 1.9 AMI Network, MDM Related Cost Electric Deployment/Maintenance Water Deployment/Maintenance Gas Deployment/Maintenance Conservation Voltage Reduction Page 9 of 17 Table 4: Summary Cost – Benefit Assessment for AMI Investment (NPV Analysis over 18 yrs) Figure 2: Present Value of Costs & Benefit of AMI Investment is Close to Break Even (PV over 18-years, $M) *staff cost to be shared by water and natural gas funds, but shown here as allocated to gas Financial Metric Base Case Results ($Million) [A] Capital Expenditure $ (16.74) [B] Annual Operational Expense - Year 5 $ (1.90) [C] Annual CPAU/Customer Operating Benefit - Year 5 $ 3.30 [D] Present Value of Operating Expenses (over 18 years) $ (27.08) [E] Present Value of Operatng Benefits (over 18 years) $ 43.83 [F] Net Present Value (over 18 years) ([F]=[A]+[D]+[E]) $ 0.01 Page 10 of 17 The NPV result of $0.01 million is dependent on numerous estimates7 made in the analysis, particularly those related to staffing levels required to operate the AMI system, operational savings related to reduced manual meter reading process, and incremental customer energy/water efficiency and conservations savings achieved. As illustrated in the table 5 the NPV could range from an adverse $14.7 million to favorable $7.8 million over 18 years depending on whether the operational savings and efficiency estimates are achieved over multiple years. The base case estimates staffing synergies are achieved and 100% of the conservation goals (~2% reduction in utility consumption reduction over 5 years) are achieved. Table 5: Sensitivity of NPV of AMI Investment ($M over 18 years) Besides offering the potential to provide operational and conservation savings, AMI is a strategic investment that is critical to meet customer expectations, enable new applications, and optimize utility operations. The following benefits were difficult to quantify and were not included in the financial model.  Improved Customer Experience  Improved Reliability  Improved System Planning Capabilities  Improved Asset Utilization  Improved Water Resource Management  Timely and Accurate Meter Reading  New advanced retail rates  Meter Right-Sizing  Unauthorized Use and Tampering Detection  Improved Safety and Reduced Workman’s Compensation  Compliance with Future Legislative Requirements  Potential Grants to implement AMI Overall, given the strategic nature of the investment, and including these intangible benefits, the analysis suggests that CPAU should plan, prepare and invest in an AMI based smart grid system. 7 This investment analysis related estimates include the following: discount rate (3.5%), life of project (18 years), operating cost increase (3%), operational savings increase (1%), customer water use conservation (2.5%), customer natural gas use conservation (2%), customer electricity use conservation (1.5% residential, 0.25% commercial), conservation voltage reduction related energy conservation (0.5%), meter reading related staffing reduction (5 to 6 FTE), AMI related staffing increase (3 to 4 FTE). These estimates were based on industry experience and Palo Alto specific situations. 50%100%150% Achieved ($7.8)$0.0 $7.8 Not Achieved ($14.7)($7.0)$0.8 Conservation Goals Achieved Staffing Synergy Status Page 11 of 17 E. Policies and Procedures to Implement and Operate AMI based Utility System Implementing AMI will impact many facets of the CPAU organization and customer interactions. In addition to early stage communication and feedback from CPAU staff and customers, operational policies and procedures must be evaluated and updated with UAC and Council input. A brief description of these operational areas and the corresponding sections under the current Rules and Regulations are listed below. 1. Discontinuance, Termination and Restoration of Service (RR 09): Need to include policy and procedure to remotely disconnect for electric meters. These policy changes will coincide with business process changes and the potential for allowing same-day and after-hours disconnects/reconnects. 2. Meter Reading (RR 10): CPAU will need to revisit the billing period of 27-33 days during re-engineering of business processes. If desired, this window can be condensed with AMI reads available daily. Also, abnormal conditions and bill estimation techniques may change with AMI/MDMS systems in place. CPAU must also consider whether the “Customer Reads Own Meter” Program will continue under AMI. New rules and fees related to customers who opt-out of the AMI meter installations on their premises will also have to be developed. In the event meter reads are not available over an extended period of time due to technology malfunction or cyberattack, an alternative customer billing process will also have to be defined. 3. Billing, Adjustments, and Payment of Bills (RR 11): Language related to theft needs to be reviewed and updated to accommodate AMI. Language related to water leaks at customer premises will have to be reviewed given that AMI has the ability to alert customers and CPAU about potential water leaks. 4. Meter Installation (RR 15). Sections related to meter seals, tampering, and meter testing will also have to be reviewed and updated. Some policies may not be fully defined until AMI systems are selected and business process re- engineering are completed. These exercises will help inform which direction the policies will shift. F. Coordinated Implementation with Technology Projects – Technology Roadmap The technology road map is about CPAU’s future technological capabilities and ensures that technology investments are aligned with CPAU’s strategic plan. It sets the expectations for deliverables, time frames for development, complexity of the system, and the level of integration required. Several large scale technology projects are expected to be implemented in the 2018-2022 period, namely CIS, ERP and AMI. Proper planning and coordinated execution is critical for the successful implementation and operation of these projects. Management focus is required to ensure projects are properly sequenced and sufficient expert resources are made available to effectively execute on projects. In addition to numerous CPAU and IT department Page 12 of 17 staff involvement, the AMI project is expected to outsource meter installation, system integration and project management services to industry experts in their respective areas. The current AMI implementation timeline, developed in coordination with CIS and ERP project implementation timeline, is shown below. • Develop AMI/MDM system specification & issue RFP to select vendor Fall 2018 • AMI/MDM system vendor selection and procurement Spring 2019 • MDM system implementation and integration with CIS completion Spring 2021 • AMI meter installation completion Summer 2022 • System Testing and Going Live with AMI based billing system Fall 2022 • Leverage AMI system to enable other utility and customer programs 2023+ Table 6 provides a coordinated timeline for implementing AMI, along with the CIS and ERP systems implementation. Table 6: Timelines for Coordinated Implementation of AMI, with CIS and ERP Systems Key: Q4-2017 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Energy Efficiency Program Optimization (EEO) (TBD) Technology Systems (Est. Capital Cost) Year 1 - 2018 Year 2 - 2019 Year 3 - 2020 OMS & AMI Integration Distribution System Optimization, CVR Customer Time-of- Use Rates Expansion New EE Programs, DR programs Utility Strategic Plan Development R e - a s s e s s m e n t P h a s e AMI/MDMS ProcurementAMI/MDMS System Spec Data Cleansing - field checks, master data clean-up CIS Stabilization Issue ERP RFP and Retain Vendor Implement New ERP HR Module Implement New ERP Finance Module Develop Technology Roadmap Note: Early selection of AMI vendor allows meter replacements to resume as planned, ahead of mass installation of AMI meters. Future Programs that are dependent on AMI Dates and $ TBD Integrate CIS to SAP & MUA Data Conversion: Create existing Customers in CIS Implement CIS + Integration with existing SAP/ERP systemCIS Design PhaseIssue CIS RFP and Retain Vendor 300 Home Customer Connect / TOU Rate Pilot Program - Maintenance Phase Full Deployment (by route/cycle) Improvement of Energy Efficiency Program Promotions based on new CIS/AMI - Planning and Pilots, on going Technology Deployment Advanced Metering Infrastructure (AMI) & Meter Data Management System (MDMS) ($17 to $19 M) Future ProjectIn Progress Alpha Phase AMI/MDMS Implementation Beta Phase AMI/MDMS Implementation Integrate MDMS to CIS, MUA, AMI Head End System (HES), OMS & GIS Enterprise Resource Planning (ERP) (UTL share $1 to $2 M) Customer Information System (CIS) ($4-5M) In Planning Flexible Billing & Payment Solution Year 5 - 2022Year 4 - 2021 ERP Design Phase Integrate new ERP with CIS Years 6+ Dependent on CIS Coordination Dependent on CIS/MUA Dependent on AMI Dependent on AMI Dependent on AMI Coordination Dependent on AMI Page 13 of 17 While the mechanics of AMI implementation well understood 8, staff is particularly aware of the workload and coordination challenges related to implementing three major technology projects within five years. The timeline presented would be evaluated by the end of CY 2018 as the CIS project implementation makes progress. G. Change Management & Staffing Resource Needs Since AMI will transform many facets of utility operations and impact the customer communication channel and utility customer programs, proper planning and communication must be undertaken within the organization and with the community. AMI involves advanced applications, complex system integrations, and new business processes. It could impact hundreds of business processes at CPAU and will require staff to perform new tasks and develop different skill sets. Utilities will need to make adjustments to its hiring and training programs to ensure proper staffing with the right knowledge to deploy and operate the AMI network. Communicating the changes and helping staff understand the value of the new system is critical to a successful AMI deployment. During the Utilities Strategic Planning (USP) engagement process in 2017, open conversations took place among staff members and the community which identified the need for an AMI system; hence, there is a high level awareness of the importance of AMI. CPAU and Human Resources have begun the process of identifying new training programs and evaluating alternate career path options within the organization for meter reading staff whose roles may largely be eliminated if AMI is implemented. The analysis also identified the need for new staffing roles. These 3-4 new staffing roles include an AMI system technician, a data analyst, an AMI infrastructure maintenance technician, a CVR program maintenance engineer/tech, and an AMI program manager. Several of these roles are part-time roles that can be combined with other existing roles. The new roles will evolve and be defined at various stages of the project. During the 2-3 year implementation and system stabilization phase, temporary staff will be hired in the Utilities Customer Service center to temporarily backfill customer service reps that will be assisting on the project. Utilities will seek UAC and Council approval for these new positions during the annual budget process. H. Community and UAC Input During the USP development process in 2017, many community members and UAC Commissioners expressed the need for CPAU to invest in an AMI system. The 2018 USP identified the implementation of an AMI system as a key strategy under the Technology Priority to “Invest in and utilize technology to enhance customer experience and maximize operational efficiency.” 8 CPAU’s consultant UWC has served as project manager on behalf of numerous utilities which have successfully implemented AMI. CPAU staff has also gained experience through the implementation of Palo Alto’s AMI pilot project and by learning from the experience of other utilities. Page 14 of 17 Staff presented the preliminary findings of UWC analysis at the November 1, 2017 UAC meeting9. The analysis concluded that AMI investment was essential for effective utility operations in the coming decade. In addition, the UAC Commissioners voted 5-1 to proceed with planning an AMI investment. This memo and accompanying consultant report seeks a formal recommendation from the UAC to Council to make the necessary investment to implement AMI. Upon formal approval by Council, staff will begin a concerted effort to engage CPAU staff and the community to identify and address any lingering concerns they may have regarding such investment and resulting changes. I. AMI Project Implementation/Operating Risks and Risk Mitigation Strategies AMI systems are well proven technologies. They have been operating successfully in most California-based utilities and throughout the United States for about a decade. Hence, with many vendors offering AMI system products, the operating reliability risk associated with AMI technology is relatively low. As of this assessment, 36 risks have been identified and categorized into 8 different types: budget, community, organizational change management, resources, schedule, scope, security, and technology. Each risk is assigned a risk impact (representing the potential impact of the risk, should the risk come to fruition) and a risk probability (representing the likelihood of the risk ever occurring during the course of the project), each of which is rated as “high”, “medium”, or “low”. The combination of these two vectors generates a risk map, illustrating the priority of said risk. Outlined below are five of the top Palo Alto-specific risks, along with the associated mitigation steps: 1. Upcoming technology projects, particularly the CIS project, may compete for resources with the AMI project. Ensure adequate planning and resources so that the AMI project implementation and integration with the CIS happens well after the implementation of the CIS and after the new CIS system begins stable operations. 2. Poor staff engagement and communication, and lack of focused change management plans; external stakeholder communication will also be paramount. Communication will be made key area of focus during implementation. 3. Ill-defined vendor contracts will lead to improper level of configuration or missing integration. Consultant assistance will be sought in this area to minimize the risk. 4. Poor system integration to existing and future utility IT applications such as GIS, CIS, ERP, Asset management, OMS, etc. Organizational requirements gathering, planning and procurement management will be key to mitigate this risk. Clear vision of project milestone and key performance indicators need to be developed and accepted within organization. 9 The preliminary analysis in November 2017 showed a NPV of negative $7 million. The updated analysis outlined here included additional efficiency/conservation benefits and synergies related to staffing AMI operations and maintenance, resulting in the NPV being estimated at $0.01 million. Currently this is the consultant’s and staff’s best estimate, within the uncertainty band outlined. Page 15 of 17 5. Lack of Council approved policies and protocols to effectively respond in the new technology environment. Examples include policies covering billing disruption, remote meter turn on/off, and mitigation of impacts caused by cyber-attacks. Ensure such policies are drafted with community input for Council approval. NEXT STEPS Upon UAC consideration and recommendation, staff will seek approval from Council. A tentative capital budget has been included in the FY19 budget for Council discussion and approval in June. The report would be brought for Council discussion in the summer. If approved, consultants would be retained to assist with AMI system procurement (2018-19) and AMI implementation (2020-22). RESOURCE IMPACT The costs of these investments have been included in the proposed FY 2019 Capital Budget (Project EL-11014, Smart Grid Installation). The funding and major activities for the five years are outlined below. AMI Budgets & Spending Timeline: A Pause in New Funding Needs in FY 2020 Assumed 10 Fiscal Year Funding Major Activities FY 2019 $1,000,000 Consultant assisted development of AMI/MDM system specifications in preparation for an RFP, issue RFP, sign contracts with MDM and AMI vendors for delivery in 2021 and 2022, respectively. In parallel, CIS implementation is beginning. FY 2020 $0 Smart grid implementation on hold pending completion of CIS implementation. Assuming no additional funding needed in FY 2020. Water meter replacement project will be undertaken. FY 2021 $3,000,000 MDMS system and AMI head-end software delivered; begin integration with CIS in January 2021. Alpha and Beta phase of testing with AMI meters. FY 2022 $10,000,000 AMI meters delivered and mass installation begins. Complete integration with CIS. FY 2023 $5,000,000 Complete meter installation, integrated system testing, go live. TOTAL $19,000,000 10 The schedule in Table 1 is based on the Technology Roadmap and assumes most funding is needed in FY 2021, FY 2022, and FY 2023. No additional funds would be needed in FY 2020 while CIS implementation is completed. The FY 2019 Capital Budget does not reflect this updated schedule, but it will be reflected in the FY 2020 Capital Budget. Page 16 of 17 The impact of these costs on each utility for the next 5 years is shown below.11 The cost responsibility for the water and gas utilities is implemented through scheduled fund transfers to the electric fund, where the capital funds are budgeted. While the Electric Special Projects (ESP) reserve is available to fund the electric portion of the investment, the Gas and Water Funds will have to cover their associated costs through reserves and rate adjustments. If the natural gas and water AMI investment funds are collected from retail rates in the short term, it may result in an adverse impact on customer retail rates. An alternate arrangement of funding the cost could be through an inter-fund loan from the ESP to the water and natural gas fund, with a loan repayment including interest over time. This alternate funding mechanism will be further investigated by staff and brought forward for UAC and Council consideration if feasible. During the implementation and system stabilization phase, project management support would be provided by a consultant with experience in managing AMI project implementations. Collaboration with Northern California Power Agency (NCPA) is also under consideration. The series of major IT projects (CIS, ERP, and AMI) will require extensive staff time over the five year implementation period. At the peak of the project, nine to twelve FTE may be dedicated to the project. About half of the staff members focusing on the project will be business analysts whose full-time job is to implement IT projects. This means that any other major IT efforts aside from the ERP, CIS, and AMI systems will be deferred. Other staff focused on the project will be drawn from various Divisions of the Utilities Department, such as Customer Service, Operations, and Engineering to manage aspects of the project specific to their area of expertise. To minimize service impacts in those Divisions, some temporary staff will be brought on using the capital project budget listed above to reduce the service impacts resulting from redirecting staff who normally do not focus on IT implementation. The project may also result in increases in overtime, deferral of discretionary projects (for example, lower priority process changes or significant new rate designs might be deferred), and there may occasionally be some service impacts, such as small increases in call times or meter replacement times. Service levels will be 11 Half of the common fixed costs of the project were allocated based on meter count, and the other half of the fixed costs were allocated to the electric utility, in recognition of the electric utility being the main driver for this investment. Based on the above allocation methodology, it is recommended that the $4.4 million in common cost related to project management, network installation and MDM/CIS integration be allocated to electricity, water and gas funds on a 70%, 14%, 16% basis respectively. Capital Budget Projections for AMI Project Electric Gas Water Total FY 2019 0.53 0.18 0.29 1.00 FY 2020 0.00 0.00 0.00 0.00 FY 2021 1.59 0.54 0.87 3.00 FY 2022 5.30 1.80 2.90 10.00 FY 2023 2.65 0.90 1.45 5.00 Total 10.07 3.42 5.51 19.00 Page 17 of 17 monitored, and if there are significant decreases in service quality, additional temporary staffing or consultant help would be used to reduce service impacts. Post-implementation, three to four new permanent roles would be needed to operate and leverage the AMI system. This additional headcount would be off-set by the reduction in meter reader staff headcount. CPAU and Human Resources have begun the process of identifying new training programs and evaluating alternate career path options within the organization for meter reading staff whose roles may largely be eliminated with AMI implementation. Upon implementation of all three projects, the expectation is that there will be a net of one to two position reductions – though the overall staffing cost is projected to be higher due to the higher skill levels needed to manage the AMI system. POLICY IMPLICATIONS The recommendation conforms with the 2018 Utilities Strategic Plan (USP) that has identified implementation of AMI system as a key strategy under USP Priority#2 to “Invest in and utilize technology to enhance customer experience and maximize operational efficiency.” A number of policies to implement and operate an AMI system must be considered and approved at a later time. Such policies and procedures include fees that CPAU may need to charge customers that opt not to allow the installation of advanced meters at their homes, a backup customer billing process in the event AMI meters are cannot be read remotely due to a cyber-attack or a communication network interruption, as well as ways of managing other potential AMI operating issues. ENVIRONMENTAL REVIEW The Utilities Advisory Commission’s recommendation to approve the investment in AMI system does not meet the definition of a project under Public Resources Code 21065; therefore, the California Environmental Quality Act (CEQA) review is not required. ATTACHMENTS •Attachment A: Smart Grid Assessment & Utilities Technology Plan - UWC Full Report •Attachment B: Excerpts of the UAC Meeting Discussions on November 1, 2017 PREPARED BY: TAHA FATTAH, Business Analyst SHIVA SWAMINATHAN, Senior Resource Planner DAVE YUAN, Utilities Strategic Business Manager REVIEWED BY: TOM AUZENNE, Assistant Director, Customer Support Services DEAN BATCHELOR, Utilities Chief Operating officer JONATHAN ABENDSCHEIN, Assistant Director, Resource Management APPROVED BY: _____________________________________ ED SHIKADA General Manager of Utilities 1 ATTACHMENT B Excerpts of Meeting Minutes from the Utilities Advisory Commission Meeting of 05-02-3018 ITEM 1: ACTION: Staff recommendation that the Utilities Advisory Commission recommend the City Council accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan including advanced metering infrastructure-based smart grid systems to serve electricity, water, and natural gas utility customers. Jeff Hoel believed the correct financial calculation showed a loss of $7.3 million over 18 years. The current time-of-use (TOU) rate provides discounts at night when electric vehicle (EV) users are charging their vehicles. He wondered about the EV users' reaction if TOU discounts occurred during the day. Replacing gas and water meters because of dead batteries would be a cost and nuisance over time. He questioned whether staff would learn of dead batteries quickly. He questioned whether the number of data samples would provide sufficient information to persuade anybody to increase conservation. Meters should not encrypt data before sending it. Chair Danaher announced the current discussion is introductory, and a vote on staff's recommendation will be taken at a subsequent meeting so that Commissioners have more time to study the document. The UAC may wish to draft an informational report of its thoughts to the Council following a recommendation to the Council. Dean Batchelor, Chief Operating Officer, announced the item will return to the Commission in August for further discussion. Jonathan Abendschein, Assistant Director of Resource Management, advised that the report represents an initial high-level exploration of the cost and benefits of advanced metering infrastructure (AMI) and a high-level map of the work leading to implementation. The UAC's vote to accept the Smart Grid Assessment and Utilities Technology Implementation Plan (Plan) would indicate staff is planning appropriately. Over time, the Council will need to approve multiple policies, procedures, budgets, and contracts. Throughout the process, the Plan can be refined. Shiva Swaminathan, Senior Resource Planner, reported the Plan recognizes three major elements of technology projects that staff is going to undertake in the next five years, the Customer Information and Billing System (CIS), the Enterprise Resource Planning System (ERP), and advanced metering infrastructure (AMI). When work on these elements begin in earnest, other projects may have to be delayed or not initiated until these three projects are complete. Staff views the investment costs as equipment and vendor costs, which total approximately $16.5 million. Staff estimated additional staffing-related costs at $1-$2 million. The Capital Improvement Program (CIP) amount of $19 million is comprised of $10 million for electric, $5 million for water, and $3.5 million for gas. Electric meters will be replaced, but radios will be placed on water and gas meters. The water and gas meter radios operate on batteries and, when the battery runs out, the radio will be replaced. Chair Danaher calculated a cost per residence of approximately $700. Swaminathan clarified that the typical measurement is cost per meter. Staff plans to install approximately 72,000 meters at a cost of $300 per meter. Staff proposes funding the electric portion of the project through the Electric Special Project Reserve. The water and gas portions of the project could 2 be funded through capitalization or financing over a 20 or 10-year term. The primary financial benefits of the project are reduction in meter reading costs and increased conservation. Staff did not quantify non-financial benefits such as improved reliability and better customer experience. In November, staff presented the net present value (NPV) as negative $7 million over 18 years. Since November, staff has determined there could be greater synergies in staffing and utilization of devices for greater conservation. These changes result in a breakeven NPV. Implementing AMI will require review of policies, procedures, and staffing resources and receipt of community and staff input. Change management and communication is a key part of the project. A transition plan is being discussed and developed for staff as roles change. Selection of technology will be relatively easy as the technology is mature. Staff has identified approximately 35 risks, the top five of which are sufficient resources, staff engagement and communication, definition of vendor contracts, integration of software, and Council approval of policies and protocols. With respect to the impact of the project on utility bills and rates, the project is a winner across the full utility and for each utility. The overall impact on bills for residential customers is neutral. In the worst-case scenario, there could be a 0.35-0.7% impact on bills if costs are incurred but benefits do not materialize as projected. Next steps include further discussion and acceptance of the Plan in August. Some of the capital investments have been included in the fiscal year 2018-2019 CIP budget. If the UAC accepts the Plan in August, staff will present it to the Council in September. In response to Commissioner Johnston's request for additional details of staff's calculation of the NPV, Swaminathan explained that staff made assumptions initially without considering any sensitivities and calculated a value. Staff then changed the assumptions and calculated the NPV. Commissioner Johnston did not find an assessment of the likelihood of not achieving each of the savings used in calculating NPV. Swaminathan indicated staff does not have a probability for achieving each savings. Staff knows with relative certainty the capital costs, but staff has a large uncertainty around the ongoing operations and maintenance cost and the value that can be harvested from the systems. The benefits projections and assumptions contribute to NPV. Commissioner Johnston inquired about experiences from other cities that staff could utilize to minimize the risk that the systems would not communicate well with one another. Abendschein related that one of the key ways to control the risk is to hire an excellent implementer who has experience with utilities similar to City of Palo Alto Utility (CPAU). Staff is investigating different avenues to make that work. Swaminathan added that the project included a $1 million contract with expert project managers who have done this type of project multiple times with utilities similar to CPAU. The project managers will be familiar with CPAU's CIS and ERP. In reply to Commissioner Segal's question regarding the contractor being responsible for just AMI integration or CIS and ERP integration, Swaminathan clarified that integration of CIS and AMI is part of the AMI project budget. Commissioner Segal presumed CIS implementation has to anticipate integration with AMI. Swaminathan stated the consultant handling the CIS and ERP projects has subcontractors, and one of the subcontractors will understand AMI integration. There would be no direct integration between AMI and ERP, only between AMI and CIS. Vice Chair Ballantine remarked that if the infrastructure supporting telemetry did not have backup systems all the way through, then the entire telemetry network could be lost in the event of a large earthquake or other significant catastrophe. In this scenario, staff would not be able to see all the meters to identify the locations of problems. If all the nodes go to data collection boxes per neighborhood and have no backup power, they will go out the moment the utility goes out. That would be a disappointing result for the whole project. Swaminathan reported the collectors have backup batteries. Vice Chair Ballantine responded that the numbers for recovering from an earthquake are 3 significantly longer than battery life. Abendschein explained that one purpose of the battery is to pass on the last gasp of information from all of the meters so that staff has at least a snapshot of what the system looked like when the earthquake hit. Part of the disaster recovery process is getting the collectors running and getting real-time telemetry up. Vice Chair Ballantine commented that if the main hub receiving the data did not stay up to get that blast of data, then all data would be lost. Often the entire electrical infrastructure goes down even though the damaging event is localized. If receiving assets also lose power or do not have sufficient battery life to ride through that, then the data would not get to the main computer asset, which might have backup power. The longer the collectors last the more they can help staff restore the utility. Abendschein clarified that the collectors are designed to deal with exactly that problem. The battery is intended to get all that information to the main system. Batchelor added that staff should explore the length of battery life. Swaminathan advised that the battery life is days. Commissioner Forssell commented that NPV does not have to be positive in all cases. There might be nonquantifiable benefits that the CPAU wants to purchase, such as system reliability. In terms of system reliability, CPAU is already extremely reliable at more than 99%. She inquired about improvements in reliability that an AMI system could provide. Vice Chair Ballantine remarked that Korea and Japan view the reliability of U.S. electrical utilities as extremely poor. Swaminathan reported electric reliability is comprised of length of time to detect and correct the outage and proactively avoiding outages. An AMI system could provide an outage notice sooner and locate the source faster, thereby reducing the length of an outage. With AMI, staff could monitor the loads on transformers during specific time periods and proactively upgrade or replace transformers to avoid outages. Abendschein added that the economic value of reducing an outage by 15 minutes or 30 minutes is much greater for commercial customers than for residential customers, and the majority of the utility's customers are commercial. Swaminathan advised that staff attempted to monetize reliability for both commercial and residential customers using industry statistics. The value is tens of thousands of dollars a year. Commissioner Forssell assumed that type of value was included in the NPV calculation. Swaminathan indicated the values were wild guestimates and small. However, preventing an outage and reducing the length of an outage contributed to customer experience. Commissioner Forssell requested examples of customer experience benefits other than TOU rates for EV users. Swaminathan offered potential benefits of resolving billing inquiries quickly, reducing the length of a power outage, notifying customers of an outage sooner, sending a right price signal to customers, and improving demand response. Chair Danaher referred to Mr. Hoel's query regarding saving money by using Fiber to the Premises and inquired whether RF connections were a significant part of the $19 million project. Swaminathan replied no. Chair Danaher noted smart meters had been used for about 25 years; therefore, a great deal of contractor experience is available. He asked if NPV numbers were informed by the experiences of other utilities and if the NPV calculation included an escalation of labor costs. Swaminathan advised that the NPV was informed by other utilities' experiences and included a labor cost increase of 3% and a benefits increase of 1%. Commissioner Schwartz remarked that there are many examples of AMI projects and of value added to utilities. CPAU could avoid some of the painful lessons of other utilities. Technologies and applications are becoming available that CPAU could utilize right away. Implementing CIS first will allow CPAU to offer more options and services as soon as meters are installed. She recommended the UAC discuss with the consultant the kinds of functions that should be installed so that CIS will accommodate those functions from the beginning. Across the country, outage detection has become an incredibly popular customer experience benefit. Leak detection is even better for customer experience. Each customer 4 having an endpoint device that can communicate will allow CPAU to offer different programs to different customers. The UAC should discuss the kinds of consumer and business-facing programs that allow variability among customers. CPAU policy should allow customers to opt out of AMI. At a recent workshop, she learned of an account reconciliation app. Consumers who utilize the app increase their conservation. The value of AMI should not be determined by cost per meter but by system wide benefits. ACTION: No action RA DU TO: UTILITIES ADVISORY COM FROM: UTILITIES DEPARTMENT DATE. September 5, 2018 SUBJECT: ISSIDN Discussion of 2019 California Energy Standards and Associated Rooftop Solar Mandate REQUEST This is an informational report for review and discussion by the Utility Advisory ComCommission (UAC) and no action is requested. DISCUSSION Recently the California Energy Commission (CEC) adopted the 2019 California Energy Standards with an effective date of January 1st, 2020. As part of the upcoming changes, all new construction low-rise residential buildings will be required to install solar photovoltaic (PV) panels to offset the annual electrical use of the building. The UAC requested that an update on the new requirements be agendized to provide an opportunity for discussion of the utility implications. A memo to support the discussion is attached. It was generated by Integrated Design 360, a City consultant who regularly advises the City's Development Services Department., ATTACHMENTS A. Memo: "Summary of 2019 California Energy Standards Solar Photovoltaic Require integrated Design 360 ents" by PREPARED BY: JONATHAN ABENDSCHEIN, Assistant Director, Resource Management REVIEWED BY: APPROVED BY: DEAN BATCHELOR, Chief Operating Officer ED SHIKADA General Manager of Utilities Page 1 0f:1 809 Laurel street #308, San Carlos, CA 94070 Phone: 415.866.6744 Integrateddesign360.com MEMORANDUM To: Jon Abendschein, Assistant Director of Utilities, City of Palo Alto From: Melanie Jacobson, Integrated Design 360 LLC Date: August 13, 2018 Re: Summary of 2019 California Energy Standards Solar Photovoltaic Requirements Executive Summary On May 9, 2018, the State of California, California Energy Commission (CEC) announced the adoption of the 2019 California Energy Standards with an effective date of January 1st, 2020. As part of the upcoming changes, all new construction low-rise residential buildings will be required to install solar photovoltaic (PV) panels to offset the annual electrical use of the building. This memorandum contains a high-level summary of the changes to the energy standards and how the regulation will impact development in Palo Alto. Discussion Every three years, the State of California adopts new building standards that are codified in Title 24 of the California Code of Regulations, referred to as the California Building Standards Code. The 2019 California Energy Code, which resides in Chapter 6 of the California Building Standards Code, will become effective at the same time as the other sections of the building codes on January 1, 2020. The primary metric used within California Energy Code is “Time Dependent Valuation” (TDV). TDV is a normalized monetary format developed and used by the CEC for comparing electricity and natural gas savings, and it considers the cost of electricity and natural gas consumed during different times of the day and year. Energy Code compliance contains two options for compliance each using the TDV measurement. The first option is the “performance method” which is a whole-building level approach allowing for flexibility is compliance. The second option is the “prescriptive method” which contains a strict list of required measures. Historically, most new construction projects have selected the performance option due to the flexibility allowed in the building design. For general code compliance under the “performance method”, each permit application will be required to calculate a customized energy budget for the building which is defined using the “Energy Design Rating” using TDV. The Energy Design Rating Scale measures energy performance of a home using a scoring system from 1 to 100. The Energy Design Rating is comprised of two independent compliance section including the (A) “Energy Efficiency Design Rating” and (B) the “Solar Electric Generation and Demand Flexibility Design Rating”. The total Energy Design Rating for a specific building will be calculated by subtracting the (B) Solar Electric Generation and Demand Flexibility Design Rating from the (A) Energy Efficiency Design Rating. ATTACHMENT A 809 Laurel street #308, San Carlos, CA 94070 Phone: 415.866.6744 Integrateddesign360.com The solar requirements will impact new construction low-rise residential buildings, including single-family homes and multi-family buildings with less than three stories in Palo Alto. A solar photovoltaic system will be required on-site for each of these buildings to offset the annual electrical usage of that building. The exact sizing and quantity of required solar PV will be calculated using the Energy Design Rating within the energy modeling software and will be the result of several factors, including solar access and roof design. The software is targeted for release at the beginning of 2019. For residential homeowners, based on a 30-year mortgage, the Energy Commission estimates that the standards will add about $40 to an average monthly payment, but save consumers $80 on monthly heating, cooling and lighting bills. See Attachment 1 for additional “Frequently Asked Questions” published by the California Energy Commission. The 2019 California Energy Standards has outlined several exceptions in the code related to the solar photovoltaic requirements. Homeowners who install battery storage systems in conjunction with photovoltaics may reduce their PV size by twenty-five percent. The code will also allow for exceptions with relation to existing permanent natural or manmade barriers external to the dwelling, including but not limited to trees, hills, and adjacent structures. In addition, homeowners who participate in a CEC-approved offsite-generation programs may offset part or all of the solar electric generation required to comply with the Standards. These programs include community shared solar electric generation systems, other renewable electric generation system, or a community shared battery storage system. The system must provide dedicated power, utility energy reduction credits, or payments for energy bill reductions. The CEC has confirmed that community or shared solar programs will be accounted for equally against on-site generation when sizing the PV system. The amount of solar required to be installed to off-set energy consumption will not change whether it’s procured through community solar or generated onsite. As a complement to the PV requirements, the standards encourage demand responsive technologies including battery storage and heat pump water heaters. However, all-electric homes without a gas hook-up will likely have to install larger photovoltaic systems than houses connected to natural gas. Early code discussions included both gas and electricity as part of Energy Design Rating calculation to apply the PV requirements. However, gas was eliminated in the final release of the code. According to a CEC publication, “because the grid is cleaner and residential rooftop solar customer compensation for over generation is very limited, it is critical that rooftop solar generation does not substantially exceed the home’s electricity use”. The codified language of the Energy Standards is targeted for release is July of 2019. The enforcement of the new requirements will be applied to new permit applications submitted on or after January 1st, 2020 in Palo Alto. The effective date of the 2019 Building Energy Efficiency Standards is January 1, 2020 What are Building Energy Efficiency Standards? Building energy efficiency standards are designed to reduce wasteful, uneconomic, inefficient or unnecessary consumption of energy, and enhance outdoor and indoor environmental quality. The standards are adopted into the California Code of Regulations (Title 24, Part 6). They apply to newly constructed buildings and additions and alterations to existing buildings. THE CALIFORNIA ENERGY COMMISSION | EFFICIENCY DIVISION 2019 Building Energy Efficiency Standards Frequently Asked Questions MARCH 2018 Standards ensure that builders use the most energy efficient and energy conserving technologies and construction practices, while being cost effective for homeowners over the 30-year lifespan of a building. The California Energy Commission is responsible for adopting, implementing and updating the standards every three years. Local city and county enforcement agencies have the authority to verify compliance with all applicable building codes including these standards. How much energy will the 2019 standards save? Single-family homes built with the 2019 standards will use about 7 percent less energy due to energy efficiency measures versus those built under the 2016 standards. Once rooftop solar electricity generation is factored in, homes built under the 2019 standards will use about 53 percent less energy than those under the 2016 standards. This will reduce greenhouse gas emissions by 700,000 metric tons over three years, equivalent to taking 115,000 fossil fuel cars off the road. Nonresidential buildings will use about 30 percent less energy due mainly to lighting upgrades. How much will the 2019 standards add to the cost of a new home? On average, the 2019 standards will increase the cost of constructing a new home by about $9,500 but will save $19,000 in energy and maintenance costs over 30 years. Based on a 30-year mortgage, the Energy Commission estimates that the standards will add about $40 per month for the average home, but save consumers $80 per month on heating, cooling and lighting bills. “The buildings that Californians buy and live in will operate very efficiently while generating their own clean energy. They will cost less to operate, have healthy indoor air and provide a platform for ‘smart’ technologies that will propel the state even further down the road to a low emissions future.” - Commissioner Andrew McAllister energy.ca.gov | facebook.com/CAEnergy | twitter.com/calenergy CALIFORNIA ENERGY COMMISSION Edmund G. Brown Jr. Governor Robert B. Weisenmiller, Ph.D. Chair Drew Bohan Executive Director Commissioners Karen Douglas, J.D. David Hochschild J. Andrew McAllister, Ph.D. Janea A. Scott, J.D. What is new to the 2019 standards? The standards require solar photovoltaic systems for new homes. For the first time, the standards establish requirements for newly constructed healthcare facilities. On the residential side, the standards also encourage demand responsive technologies including battery storage and heat pump water heaters and improve the building’s thermal envelope through high performance attics, walls and windows to improve comfort and energy savings. In nonresidential buildings, the standards update indoor and outdoor lighting making maximum use of LED technology. For residential and nonresidential buildings, the standards enable the use of highly efficient air filters to trap hazardous particulates from both outdoor air and cooking and improve kitchen ventilation systems. Do the 2019 residential standards get us to zero net energy? Homes built in 2020 and beyond will be highly efficient and include photovoltaic generation to meet the home’s expected annual electric needs. Because smarter buildings perform better and affect the grid less, the standards also include voluntary options to install technology that can shift the energy use of the house from peak periods to off-peak periods. In 2008, California set energy-use reduction goals targeting zero-net-energy use in all new homes by 2020 and commercial buildings by 2030. The goal meant that new buildings would use a combination of energy efficiency and distributed renewable energy generation to meet all annual energy needs. However, California’s energy landscape has changed since then. Two important policies – the Renewable Portfolio Standards (RPS) and net energy metering rules (NEM) – affect the value of rooftop solar generation. The RPS requires utilities to have 50 percent of their electrical resources come from renewables by 2030. As a result, electricity produced for the grid is already much cleaner than 10 years ago. NEM rules limit residential rooftop solar generation to produce no more electricity than the home is expected to consume on an annual basis. If the home generates more, the surplus is compensated at much lower than the retail rate (which can be a difference of $.10 a kilowatt-hour or more). The Energy Commission’s standards must be cost effective and bring value to the grid and environment. Because the grid is cleaner and residential rooftop solar customer compensation for over generation is very limited, it is critical that rooftop solar generation does not substantially exceed the home’s electricity use. It is ideal to generate the electricity and have it used onsite versus exporting it to the grid at a time it may not be needed. When the rooftop solar generation is entirely used to offset on-site electricity consumption, then the home has virtually no impact on the grid, reducing the home’s climate change emissions. Looking beyond the 2019 standards, the most important energy characteristic for a building will be that it produces and consumes energy at times that are appropriate and responds to the needs of the grid, which reduces the building’s emissions. Selected 2019 Building Energy Standards Code Sections – Exceptions to Solar Mandate 7.2.2 Exceptions to PV requirements There are six allowable exceptions to the prescriptive PV requirements as listed below. Exception 1 may apply if there is limited unshaded roof space. No PV is required if the effective annual solar access is restricted to less than 80 contiguous square feet by shading from existing permanent natural or manmade barriers external to the dwelling, including but not limited to trees, hills, and adjacent structures. The effective annual solar access shall be 70 percent or greater of the output of an unshaded PV array on an annual basis. Exception 2 may apply to climate zone 15 and the required PV size can be reduced. The PV size shall be the smaller of a size that can be accommodated by the effective annual solar access or a PV size required by the equation above, but no less than 1.5 Watt DC per square foot of conditioned floor area. Exception 3 may apply to two stories residential buildings and the required PV size can be reduced. shall be the smaller of a size that can be accommodated by the effective annual solar access or a PV size required by the Equation 150.1 - C, but no less than 1.0 Watt DC per square foot of conditioned floor area Exception 4 In all climate zones, for low - rise residential dwellings with three habitable stories and single family dwellings with three or more habitable stories, the PV size shall be the smaller of a size that can be accommodated by the effective annual solar access or a PV size required by the Equation 150.1 - C, but no less than 0.8 Watt DC per square foot of conditioned floor area. Solar Ready - Performance Approach Compliance for Photovoltaic System Page 7 - 3 2019 Residential Compliance Manual June 2018 Exception 5 For a dwelling unit plan that is approved by the planning department prior to January 1, 2020 with available solar ready zone between 80 and 200 square feet, the PV size is limited to the lesser of the size that can be accommodated by the effective annual solar access or a size that is required by the Equation 150.1 - C. Except ion 6 may apply to buildings with battery storage system. The required PV sizes from Equation 7 - 1 may be reduced by 25 percent if a battery storage system is installed. For single family building, the minimum capacity of the battery storage system must be at least 7.5 kWh. For multifamily buildings, the battery storage system must have a minimum total capacity equivalent to 7.5 kWh per dwelling. In all case the battery storage needs to meet the qualification requirements specified in Joint Appendix JA12 and be listed with CEC. 7.4 Community Shared Electric Generation System The 2019 Building Energy Efficiency Standards allow the possibility for the Standards requirements for photovoltaics on the site of the residential building to be fully or partially offset by Community Shared Solar Electric Generation. Community Shared Solar Electric Generation means solar electric generation or other renewable technology electric generation that is installed at a different site. Also, the batteries that can be installed in combination with photovoltaics on the building site to gain performance standards compliance credit can be fully or partially offset by Community Shared Battery Storage Systems that are installed at a different site. Community Shared Solar Electric Generation Systems and Community Shared Battery Storage Systems could be installed in combination or separately. Such systems are hereinafter referred to just as Community Shared Solar Generation Systems. For these offsets to become available, entities who wish to serve as administrators of a proposed Community Shared Solar Electric Generation System must apply to the Energy Commission for approval, demonstrating that several criteria specified in Section 10 - 115 of the Standards are met, to ensure that the Community Shared Solar Generation System provides equivalent benefits to the residential building expected to occur if photovoltaics or batteries had been installed on the building site. The Energy Commission will carefully consider these applications to determine if they meet these criteria. If approved, Energy Commission approved compliance software will be modified to enable users to take compliance credit for buildings served by that Energy Commission approved Community Shared Solar Electric Generation System. Any entity may apply to serve as administrator of a proposed Community Shared Solar Electric Generation System, including but not limited to utilities, builders, solar companies or local governments. The entity will be responsible for ensuring that the criteria for approval are met throughout (at least) a twenty - year period for each building that uses shares of the Community Shared Solar Electric Generation System for partial or full offset of the onsite solar electric generation and batteries, which would otherwise be required for the building to comply with the Standards. Throughout that period the administrator will be accountable to builders, building owners, enforcement agencies, the Energy Commission, and other parties who relied on these systems for offset of full or partial compliance with the Standards. Records demonstrating compliance with the criteria must be maintained over that period, with access to those records provided to any entity approved by the Energy Commission. Entities interested in applying to serve as administrator of a proposed Community Shared Solar Electric Generation System should become thoroughly familiar with the criteria for approval specified in Section 10 - 115, and contact the Energy Commission Building Standards Office for further discussion and explanation of the criteria as necessary. In general, the Community Shared Solar Electric Generation System must meet the following: A. Enforcement Agency The Community Shared Solar Electric Generation System must exist and be available for enforcement agency review early in the permitting process, and shall not cause delay in the in enforcement agency review and approval of the building that will be served by the Community Shared Solar Generation System. All documentation required to demonstrate compliance for the building and the compliance offset from the Community Shared Solar Electric Generation System shall be completed and submitted to the enforcement agency with the permit application. The enforcement agency must be provided facilitated access to the Community Shared Solar Electric Generation System to verify the validity and accuracy of compliance documentation. B. Energy Performance Energy Commission approved compliance software must be used to show that the energy performance of the building’s share of the Community Shared Solar Electric Generation System is equal to or greater than the partial or full offset claimed for the solar electric generation and batteries, which would otherwise be required for the building to comply with the Standards. C. Dedicated Building Energy Savings Benefits A specific share of the Community Shared Solar Electric Generation System, determined to comply with the Energy Performance requirement above, must be dedicated on an ongoing basis to the building. The energy savings benefits dedicated to the building shall be provided in one of the following ways: • Actual reductions in the energy consumption of the building; • Utility energy reduction credits that will result in virtual reductions in the building’s energy consumption that is subject to energy bill payments; or • Payments to the building that will have an equivalent effect as energy bill reductions that would result from one of the other two options above. The reduction in energy bills resulting from the share of the Community Shared Solar Electric Generation System dedicated to the building shall be greater than the cost that is charged to the building to obtain that share of the Community Shared Solar Electric Generation System. D. Durability The benefits from the specific share of the Community Shared Solar Electric Generation System must be provided to each dedicated building for a period not less than 20 years. E. Additionality The specific share of the Community Shared Solar Electric Generation System must provide the benefits to the dedicated building that are in no way made available or attributed to any other building or purpose. Renewable Energy Credits that are unbundled from the Community Shared Solar Electric Generation System do not meet this additionality requirement.